Exhibit 99.2

Management’s discussion and analysis

for the quarter ended March 31, 2015

FIRST QUARTER UPDATE	4
CONSOLIDATED FINANCIAL RESULTS	8
OUTLOOK FOR 2015	15
LIQUIDITY AND CAPITAL RESOURCES	17
FINANCIAL RESULTS BY SEGMENT
URANIUM	18
FUEL SERVICES	20
NUKEM	20
OUR OPERATIONS	21
URANIUM 2015 Q1 UPDATES	21
FUEL SERVICES 2015 Q1 UPDATES	23
QUALIFIED PERSONS	23
ADDITIONAL INFORMATION	23

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, 2015 (interim financial statements). The information is based on what we knew as of April 28, 2015 and updates the annual MD&A included in our 2014 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, 2014 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, including NUKEM Energy Gmbh (NUKEM), unless otherwise indicated.

- 1 -

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 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 on pages 2 and 3. 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 2015 and future global uranium supply and demand and number of reactors including the discussion under the heading Uranium market update

• the discussion of our expectations relating to our transfer pricing disputes including our estimate of the amount and timing of expected cash taxes and transfer pricing penalties

• our consolidated outlook for the year and the outlook for our uranium, fuel services and NUKEM segments for 2015

• our expectations for uranium deliveries in the second quarter and for the balance of 2015

• our price sensitivity analysis for our uranium segment

• our expectation that existing cash balances and operating cash flows will meet our anticipated 2015 capital requirements without the need for any significant additional funding

• our expectation that our operating and investment activities for the remainder of 2015 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

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 or loss of market share to a competitor

• we are adversely affected by changes in foreign currency exchange rates, interest 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 estimates of production, purchases, costs, decommissioning or reclamation expenses, or our tax expense estimates, 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 disputes with tax authorities

• 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

• there are defects in, or challenges to, title to our properties

• our mineral reserve and resource estimates are not reliable, or we face unexpected or challenging geological, hydrological or mining conditions

• we are affected by environmental, safety and regulatory risks, including increased regulatory burdens or delays

• we cannot obtain or maintain necessary permits or approvals from government authorities

• 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

2     CAMECO CORPORATION

• there are changes to government regulations or policies that adversely affect us, including tax and trade laws and policies

• our uranium suppliers fail to fulfil delivery commitments

• our McArthur River development, mining or production plans are delayed or do not succeed for any reason

• our Cigar Lake development, mining or production plans are delayed or do not succeed, including as a result of any difficulties with the jet boring mining method or freezing the deposit to meet production targets, the third jet boring machine does not go into operation on schedule in 2015 or operate as expected, or any difficulties with the McClean Lake mill modifications or expansion or milling of Cigar Lake ore

• we are unable to obtain an extension to the term of Inkai’s block 3 exploration licence, which expires in July 2015

• we are affected by natural phenomena, including inclement weather, fire, flood and earthquakes

• our operations are disrupted due to problems with our own or our customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failures, transportation disruptions or accidents, or other development and operating risks

Material assumptions

• our expectations regarding sales and purchase volumes and prices for uranium and fuel services

• our expectations regarding the demand for uranium, the construction of new nuclear power plants and the relicensing of existing nuclear power plants not being more adversely affected than expected by changes in regulation or in the public perception of the safety of nuclear power plants

• our expected production level and production costs

• the assumptions regarding market conditions upon which we have based our capital expenditures expectations

• our expectations regarding spot prices and realized prices for uranium, and other factors discussed under the heading Price sensitivity analysis: uranium segment

• our expectations regarding tax rates and payments, foreign currency exchange rates and interest rates

• our expectations about the outcome of disputes with tax authorities

• our decommissioning and reclamation expenses

• our mineral reserve and resource estimates, and the assumptions upon which they are based, are reliable

• the geological, hydrological and other conditions at our mines

• our McArthur River development, mining and production plans succeed

• our Cigar Lake development, mining and production plans succeed, including the third jet boring machine goes into operation on schedule in 2015 and operates as expected, the jet boring mining method works as anticipated, and the deposit freezes as planned

• modification and expansion of the McClean Lake mill are completed as planned and the mill is able to process Cigar Lake ore as expected

• the term of Inkai’s block 3 exploration licence does not expire in July 2015 and is instead extended

• our ability to continue to supply our products and services in the expected quantities and at the expected times

• our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals

• our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents or other development or operating risks

2015 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 profitably produce at a pace aligned with market signals in order to increase long-term shareholder value, and to do that with a focus on safety, people and the environment.

We plan to:

• ensure continued reliable, low-cost production from our flagship operation, McArthur River/Key Lake, and seek to expand that production

• ensure continued reliable, low-cost production at Inkai

• successfully ramp up production at Cigar Lake

• manage the rest of our production facilities and other sources of supply in a manner that retains the flexibility to respond to market signals and take advantage of value adding opportunities within our own portfolio and the uranium market

• maintain our low-cost advantage by focusing on execution and operational excellence

You can read more about our strategy in our 2014 annual MD&A.

First quarter update

On January 31, 2014, we announced the sale of our 31.6% limited partnership interest in Bruce Power Limited Partnership (BPLP) and related entities for $450 million. The sale closed on March 27, 2014 and was accounted for as being completed effective January 1, 2014.

Under IFRS, we are required to report the results from discontinued operations separately from continuing operations. We have included the financial impact of the sale of BPLP in discontinued operations.

Throughout this document, for comparison purposes, all results for “earnings from continuing operations” and “cash from continuing operations” have been revised to exclude BPLP. The impact of BPLP is shown separately as a discontinued operation.

Our performance

HIGHLIGHTS	THREE MONTHS ENDED MARCH 31
($ MILLIONS EXCEPT WHERE INDICATED)	2015			2014		CHANGE
Revenue		566			419		35	%
Gross profit		129			108		19	%
Net earnings (loss) attributable to equity holders		(9	)		131		(107	)%
$ per common share (diluted)		(0.02	)		0.33		(106	)%
Adjusted net earnings (non-IFRS, see page 8)		69			36		92	%
$ per common share (adjusted and diluted)		0.18			0.09		100	%
Cash provided by operations (after working capital changes)		134			7		1814	%

FIRST QUARTER UPDATE

Net loss attributed to equity holders (net loss) this quarter was $9 million (loss of $0.02 per share diluted) compared to net earnings of $131 million ($0.33 per share diluted) in the first quarter of 2014. Our net loss was primarily due to higher mark-to-market losses on foreign exchange derivatives. In addition, our 2014 earnings included a gain on the sale of our interest in BPLP of $127 million.

On an adjusted basis, our earnings this quarter were $69 million ($0.18 per share diluted) compared to $36 million ($0.09 per share diluted) (non-IFRS measure, see page 8) in the first quarter of 2014. The change was mainly due to higher earnings from our fuel services and NUKEM segments based on higher sales volumes, partially offset by lower earnings in our uranium segment. In addition, our 2014 adjusted net earnings also included an early termination fee of $18 million incurred as a result of the cancellation of our toll conversion agreement with Springfields Fuels Ltd. (SFL), which was to expire in 2016.

4     CAMECO CORPORATION

See Financial results by segment on page 18 for more detailed discussion.

Operations update

		THREE MONTHS ENDED MARCH 31
HIGHLIGHTS		2015		2014			CHANGE
Uranium	Production volume (million lbs)		5.1		5.7			(11	)%
	Sales volume (million lbs)1		7.0		6.9			1	%
	Average realized price ($US/lb)		43.42		46.60			(7	)%
	($Cdn/lb)		52.74		50.58			4	%
	Revenue ($ millions)1		368		348			6	%
	Gross profit ($ millions)		113		119			(5	)%
Fuel services	Production volume (million kgU)		2.6		4.0			(35	)%
	Sales volume (million kgU)		3.0		1.8			67	%
	Average realized price ($Cdn/kgU)		22.11		22.41			(1	)%
	Revenue ($ millions)		66		40			65	%
	Gross profit ($ millions)		8		2			300	%
NUKEM	Sales volume U3O8 (million lbs)2		2.5		0.7			257	%
	Average realized price uranium ($Cdn/lb)		38.14		39.81			(4	)%
	Revenue ($ millions)2		97		32			203	%
	Gross profit (loss) ($ millions)		11		(3	)		467	%

¹  Includes sales and revenue between our uranium and NUKEM segments (15,000 lbs in sales and revenue of $0.5 million in Q1 2015, nil in Q1 2014).

²  Includes sales and revenue between our uranium, fuel services and NUKEM segments (0.5 million lbs in sales and revenue of $2.5 million in Q1 2015, nil in Q1 2014).

Production in our uranium segment this quarter was 11% lower compared to the first quarter of 2014, mainly due to an unplanned outage at the Key Lake mill to repair the calciner, and slightly lower production at our in situ recovery (ISR) operations. These decreases were partially offset by higher production at Rabbit Lake and at Cigar Lake. See Uranium 2015 Q1 updates starting on page 21 for more information.

Key highlights:

• At Cigar Lake, the jet boring system (JBS) performed as expected. We successfully mined 1.9 million pounds of uranium for shipment to the McClean Lake mill, which, during the first quarter, packaged approximately 690,000 pounds (100% basis, 345,000 pounds our share).

• At McArthur River, the Canadian Nuclear Safety Commission (CNSC) approved an increase of our licence production limit to 25 million pounds per year (100% basis), which matches the annual mill production licence limit at Key Lake. Provincial approval is the final step in the approval process, and we are currently awaiting a decision.

• In April, Cameco Inc. signed a supply agreement with the Department of Atomic Energy of India to provide 7.1 million pounds of uranium concentrate under a long-term contract through 2020.

Production in our fuel services segment was 35% lower this quarter than in the first quarter of 2014 due to lower planned annual production in 2015.

2015 FIRST QUARTER REPORT    5

Uranium market update

The market in the first quarter of 2015 changed little from the last quarter of 2014. The modest level of contracting activity was comparable to the previous quarter, with no significant strength or weakness emerging.

On the positive side, China started approving new reactor projects after a hiatus following the 2011 events in Japan, and four reactors under construction in China joined the grid. As a result, China now has 26 reactors operating and 23 under construction. On the supply side, production issues at several large uranium mines threaten to tighten supply in the coming year, although the market impact has not yet been significant.

Japan continued to experience difficulties with reactor restarts in 2015, although the country reported a mix of both negative and positive developments. The industry experienced another potential setback with the recent court injunction preventing the restart of Kansai Electric’s two Takahama units, which had applied for restart and had already met the Nuclear Regulatory Authority’s new safety standards. This development adds to ongoing uncertainty about the pace of restarts in Japan. Additionally, it was announced that five older reactors would not submit restart applications, but would be permanently retired. However, positive news also emerged when a provisional injunction to block the restart of the Sendai reactors was rejected by the Kagoshima District Court, allowing Kyushu Electric to remain focused on the safe restart of the facility. The frontrunners for restart continue to be the two Sendai reactors, which appear poised for restart this summer, following final regulatory approvals and pre-operational safety checks.

In the absence of a significant uptick in demand from fuel buyers, whose requirements continue to be well covered in 2015, there was modest movement in the uranium spot price from the later part of 2014. The spot price has shown some support just below $40 (US).

Looking forward, Canada’s Nuclear Cooperation Agreement with India, and Cameco Inc.’s subsequent supply agreement with India’s Department of Atomic Energy (DAE), represent significant opportunities in the world’s second fastest growing market for nuclear fuel. The sale, into a market that was previously closed to us, provides 7.1 million pounds of uranium concentrate under a long-term contract through 2020 and, we anticipate, marks the beginning of a long and positive relationship with a new customer.

Longer term, strong fundamentals underpin a positive outlook for the industry as 63 reactors are currently under construction, and a net increase of 81 reactors is expected over the next 10 years. This demand fundamental combined with the timing, development and execution of new supply projects and the continued performance of existing supply will determine the pace of market recovery.

Caution about forward-looking information relating to our uranium market update

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

Industry Prices

	MAR 31 2015		DEC 31 2014		SEPT 30 2014		JUN 30 2014		MAR 31 2014		DEC 31 2013
Uranium ($US/lb U3O8) 1
Average spot market price		39.45		35.50		35.40		28.23		34.00		34.50
Average long-term price		49.50		49.50		45.00		44.50		46.00		50.00
Fuel services ($US/kgU as UF6)1
Average spot market price
North America		7.50		8.25		7.25		7.25		7.63		8.50
Europe		8.00		8.63		7.50		7.50		8.00		9.00
Average long-term price
North America		16.00		16.00		16.00		16.00		16.00		16.00
Europe		17.00		17.00		17.00		17.00		17.00		17.00

Note: the industry does not publish UO₂ prices.

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

6     CAMECO CORPORATION

On the spot market, where purchases call for delivery within one year, the volume reported for the first quarter of 2015 was approximately 15 million pounds. This compares to approximately 10 million pounds in the first quarter of 2014.

At the end of the quarter, the average reported spot price had improved by almost four dollars from the previous quarter to $39.45 (US) per pound, while the average reported long-term price remained flat at $49.50 (US) per pound.

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).

Spot UF₆ conversion prices declined during the quarter, while long-term UF₆ conversion prices held firm.

Shares and stock options outstanding

At April 27, 2015, we had:

• 395,792,522 common shares and one Class B share outstanding

• 8,748,994 stock options outstanding, with exercise prices ranging from $19.30 to $54.38

Dividend policy

Our board of directors has established a policy of paying a quarterly dividend of $0.10 ($0.40 per year) per common share. This policy will be reviewed from time to time based on our cash flow, earnings, financial position, strategy and other relevant factors.

2015 FIRST QUARTER REPORT    7

Financial results

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

Consolidated financial results

HIGHLIGHTS	THREE MONTHS ENDED MARCH 31
($ MILLIONS EXCEPT WHERE INDICATED)	2015			2014		CHANGE
Revenue		566			419		35	%
Gross profit		129			108		19	%
Net earnings (loss) attributable to equity holders		(9	)		131		(107	)%
$ per common share (basic)		(0.02	)		0.33		(106	)%
$ per common share (diluted)		(0.02	)		0.33		(106	)%
Adjusted net earnings (non-IFRS, see page 8)		69			36		92	%
$ per common share (adjusted and diluted)		0.18			0.09		100	%
Cash provided by operations (after working capital changes)		134			7		1814	%

NET EARNINGS

Net loss attributed to equity holders (net loss) this quarter was $9 million (loss of $0.02 per share diluted) compared to net earnings of $131 million ($0.33 per share diluted) in the first quarter of 2014. Our net loss was primarily due to higher mark-to-market losses on foreign exchange derivatives. In addition, our 2014 earnings included a gain on the sale of our interest in BPLP of $127 million.

On an adjusted basis, our earnings this quarter were $69 million ($0.18 per share diluted) compared to $36 million ($0.09 per share diluted) (non-IFRS measure, see page 8) in the first quarter of 2014. The change was mainly due to higher earnings from our fuel services and NUKEM segments based on higher sales volumes, partially offset by lower earnings in our uranium segment. In addition, our 2014 adjusted net earnings included an early termination fee of $18 million incurred as a result of the cancellation of our toll conversion agreement with SFL, which was to expire in 2016.

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 more 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 better 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 write-downs and recoveries, income taxes on adjustments, impairment charges on non-producing property, and the after tax gain on the sale of our interest in BPLP.

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 our net earnings.

8     CAMECO CORPORATION

	THREE MONTHS ENDED MARCH 31
($ MILLIONS)	2015			2014
Net earnings (loss) attributable to equity holders		(9	)		131
Adjustments
Adjustments on derivatives1 (pre-tax)		101			44
NUKEM purchase price inventory recovery		(3	)		—
Income taxes on adjustments		(26	)		(12	)
Impairment charge		6			—
Gain on interest in BPLP (after tax)		—			(127	)
Adjusted net earnings		69			36

¹  We do not apply hedge accounting for our portfolio of foreign currency forward sales contracts. However, we have adjusted our gains or losses on derivatives to reflect what our earnings would have been had hedge accounting been in place.

The following table shows what contributed to the change in adjusted net earnings this quarter.

($ MILLIONS)		THREE MONTHS ENDED MARCH 31
Adjusted net earnings – 2014			36
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		2
	Lower realized prices ($US)		(22	)
	Foreign exchange impact on realized prices		37
	Higher costs		(22	)
	Hedging effects		(23	)
	change – uranium		(28	)
Fuel services	Higher sales volume Lower realized prices ($Cdn) Lower costs Hedging effects		1 (1 5 (2	)  )
	change – fuel services		3
NUKEM	Gross profit		11
	change – NUKEM		11
Other changes Lower administration expenditures Lower exploration expenditures Higher income taxes Contract cancellation fee Loss on equity-accounted investments Foreign exchange Other			3 3 (15 18 10 23 5	)
Adjusted net earnings – 2015			69

See Financial results by segment on page 18 for more detailed discussion.

2015 FIRST QUARTER REPORT    9

Quarterly trends

HIGHLIGHTS ($ MILLIONS EXCEPT PER SHARE AMOUNTS)	2015								2014									2013
	Q1			Q4		Q3			Q2			Q1		Q4		Q3		Q2
Revenue		566			889		587			502			419		977		597		421
Net earnings (loss) attributable to equity holders		(9	)		73		(146	)		127			131		64		211		34
$ per common share (basic)		(0.02	)		0.18		(0.37	)		0.32			0.33		0.16		0.53		0.09
$ per common share (diluted)		(0.02	)		0.18		(0.37	)		0.32			0.33		0.16		0.53		0.09
Adjusted net earnings (non-IFRS, see page 8)		69			205		93			79			36		150		208		61
$ per common share (adjusted and diluted)		0.18			0.52		0.23			0.20			0.09		0.38		0.53		0.15
Earnings (loss) from continuing operations		(10	)		72		(146	)		127			4		28		163		33
$ per common share (basic)		(0.02	)		0.18		(0.37	)		0.32			0.01		0.07		0.41		0.08
$ per common share (diluted)		(0.02	)		0.18		(0.37	)		0.32			0.01		0.07		0.41		0.08
Cash provided by continuing operations (after working capital changes)		134			236		263			(25	)		7		163		154		(33	)

Key things to note:

• our financial results are strongly influenced by the performance of our uranium segment, which accounted for 65% of consolidated revenues in the first quarter of 2015

• the timing of customer requirements, which tend to vary from quarter to quarter, drives revenue in the uranium and fuel services segments

• 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

• quarterly results are not necessarily a good indication of annual results due to seasonal variability in customer requirements

The table that follows presents the differences between net earnings and adjusted net earnings for the previous seven quarters.

HIGHLIGHTS ($ MILLIONS EXCEPT PER SHARE AMOUNTS)	2015									2014												2013
	Q1			Q4			Q3			Q2			Q1			Q4			Q3			Q2
Net earnings (loss) attributable to equity holders		(9	)		73			(146	)		127			131			64			211			34
Adjustments
Adjustments on derivatives1 (pre-tax)		101			10			60			(66	)		44			36			(41	)		36
NUKEM purchase price inventory write-down (recovery)		(3	)		(4	)		(2	)		—			—			(3	)		17			—
Impairment charges		6			172			196			—			—			70			15			—
Income taxes on adjustments		(26	)		(46	)		(15	)		18			(12	)		(17	)		6			(9	)
Gain on sale of BPLP (after tax)		—			—			—			—			(127	)		—			—			—
Adjusted net earnings (non-IFRS, see page 8)		69			205			93			79			36			150			208			61

¹  We do not apply hedge accounting for our portfolio of foreign currency forward sales contracts. However, we have adjusted our gains or losses on derivatives to reflect what our earnings would have been had hedge accounting been in place.

10     CAMECO CORPORATION

Discontinued operation

On March 27, 2014, we completed the sale of our 31.6% limited partnership interest in BPLP. The aggregate sale price for our interest in BPLP and certain related entities was $450 million. The sale was accounted for effective January 1, 2014. We realized an after tax gain of $127 million on this divestiture. See note 4 to the interim financial statements for more information.

	THREE MONTHS ENDED MARCH 31
($ MILLIONS)	2015		2014
Share of earnings from BPLP and related entities		—		—
Tax expense		—		—
		—		—
Gain on disposal of BPLP and related entities		—		144.9
Tax expense on disposal		—		(17.7	)
Net earnings from discontinued operations		—		127.2

Corporate expenses

ADMINISTRATION

($ MILLIONS)	THREE MONTHS ENDED MARCH 31				CHANGE
	2015		2014
Direct administration		38		38		—
Stock-based compensation		4		7		(43	)%
Total administration		42		45		(7	)%

Direct administration costs were the same as the first quarter of 2014.

Stock based compensation was $3 million lower than in 2014 due to a decrease in our share price from 2014 to 2015.

EXPLORATION

In the first quarter, uranium exploration expenses were $12 million, a decrease of $2 million compared to the first quarter of 2014.

INCOME TAXES

We recorded an income tax recovery of $45 million in the first quarter of 2015, unchanged from the first quarter of 2014. In 2015, we recorded losses of $210 million in Canada compared to $186 million in 2014, while earnings in foreign jurisdictions increased to $155 million from $144 million. The resulting increase in income tax recovery in Canada is fully offset by increased tax expense in the foreign jurisdictions.

On an adjusted basis, we recorded an income tax recovery of $20 million this quarter compared to a recovery of $34 million in the first quarter of 2014 due to higher pre-tax adjusted earnings and a change in the distribution of earnings between jurisdictions.

	THREE MONTHS ENDED MARCH 31
($ MILLIONS)	2015			2014
Pre-tax adjusted earnings1
Canada2		(103	)		(144	)
Foreign		152			145
Total pre-tax adjusted earnings		49			1
Adjusted income taxes1
Canada2		(27	)		(37	)
Foreign		7			3
Adjusted income tax expense (recovery)		(20	)		(34	)

¹  Pre-tax adjusted earnings and adjusted income taxes are non-IFRS measures.

²  Our IFRS-based measures have been adjusted by the amounts reflected in the table in adjusted net earnings (non-IFRS measure on page 8).

2015 FIRST QUARTER REPORT    11

TRANSFER PRICING DISPUTES

We have been reporting on our transfer pricing dispute with Canada Revenue Agency (CRA) since 2008, when it originated. As well, during the quarter we received a Revenue Agent’s Report (RAR) from the United States Internal Revenue Service (IRS) challenging the transfer pricing used under certain intercompany transactions including uranium purchase and sales arrangements relating to 2009. Below, we discuss the general nature of transfer pricing disputes and, more specifically, the ongoing disputes 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 between arm’s-length parties entered into at that time.

For the years 2003 to 2009, CRA has shifted CEL’s income (as re-calculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2009, transfer pricing penalties. The IRS also allocated a portion of CEL’s income for 2009 to the US, resulting in such income being taxed in multiple jurisdictions. Taxes of approximately $290 million for the 2003 – 2014 years have already been paid in a jurisdiction outside Canada and the US. Bilateral international tax treaties contain provisions that generally seek to prevent taxation of the same income in both countries. As such, in connection with these disputes, we are considering our options including remedies under international tax treaties that would limit double taxation; however, it is unclear whether we will be successful in eliminating all potential double taxation. The expected income adjustments under our tax disputes are represented by the amounts claimed by CRA and IRS and are described below.

CRA dispute

Since 2008, CRA has disputed our corporate structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2009 tax returns. We have recorded a cumulative tax provision of $87 million, where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through March 31, 2015. 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 2009, CRA issued notices of reassessment for approximately $2.8 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $820 million. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229 million. The Canadian income tax rules include provisions that require larger companies like us to remit 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions and tax loss carryovers, we have paid a net amount of $248 million cash to the Government of Canada, which includes the amounts shown in the table below. As an alternative to paying cash, we are exploring the possibility of providing security in the form of letters of credit to satisfy our requirements under these provisions.

YEAR PAID ($ MILLIONS)	CASH TAXES			INTEREST AND INSTALMENT PENALTIES		TRANSFER PRICING PENALTIES		TOTAL
Prior to 2013		—			13		—		13
2013		1			9		36		46
2014		106			47		—		153
2015		(44	)		1		79		36
Total		63			70		115		248

12     CAMECO CORPORATION

Using the methodology we believe CRA will continue to apply, and including the $2.8 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $6.6 billion of additional income taxable in Canada for the years 2003 through 2014, which would result in a related tax expense of approximately $1.9 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2009. As a result, we estimate that cash taxes and transfer pricing penalties for these years would be between $1.45 billion and $1.5 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 responsible for remitting or otherwise providing security for 50% of the cash taxes and transfer pricing penalties (between $725 million and $750 million), plus related interest and instalment penalties assessed, which would be material to us.

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. The estimated amounts summarized in the table below reflect actual amounts paid and estimated future amounts owing based on the actual and expected reassessments for the years 2003 through 2014. We will update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2014.

$ MILLIONS	2003 - 2014		2015		2016 - 2017		2018 - 2023		TOTAL
50% of cash taxes and transfer pricing penalties paid or owing in the period1		143		165 - 190		320 - 345		80 - 105		725 - 750

¹ These amounts do not include interest and instalment penalties, which totalled approximately $70 million to March 31, 2015.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to the Government of Canada, including the $248 million already paid to date.

Due to the time it is taking to work through the pre-trial process, we now expect our appeal of the 2003 reassessment to be heard in the Tax Court of Canada in 2016. If this timing is adhered to, we expect to have a Tax Court decision within six to 18 months after the trial is complete.

IRS dispute

As noted above, we received a RAR from the IRS pertaining to the 2009 tax year for certain of our US subsidiaries. The RAR lists the adjustments proposed by the IRS and calculates the tax and any penalties owing based on the proposed adjustments.

The current position of the IRS is that a portion of the non-US income reported under our corporate structure and taxed in non-US jurisdictions should be recognized and taxed in the US on the basis that:

• the prices received by our US mining subsidiaries for the sale of uranium to CEL are too low

• the compensation being earned by Cameco Inc., one of our US subsidiaries, is inadequate

The proposed adjustments result in an increase in taxable income in the US of approximately $108 million (US) and a corresponding increased income tax expense of approximately $32 million (US) for the 2009 taxation year, with interest being charged thereon. In addition, the IRS proposed penalties of approximately $7 million (US) in respect of the adjustment.

At present, the RAR pertains only tor the 2009 tax year: however, the IRS is also auditing our tax returns for 2010 through 2012 on a similar basis and we expect adjustments in these years to be similar to those made for 2009. If the IRS audits years subsequent to 2012 on a similar basis, we expect these proposed adjustments would also be similar to those made for 2009.

We believe that the conclusions of the IRS in the RAR are incorrect and we are contesting them in an administrative appeal, during which we are not required to make any cash payments. At present, this matter is still at an early stage and, until this matter progresses further, we cannot provide an estimation of the likely timeline for a resolution of the dispute.

2015 FIRST QUARTER REPORT    13

We believe that 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.

Caution about forward-looking information relating to our CRA and IRS tax disputes

This discussion of our expectations relating to our tax disputes with CRA and IRS and future tax reassessments by CRA and IRS 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 2010 through 2014 using a similar methodology as for the years 2003 through 2009, and the reassessments will be issued on the basis we expect

• we will be able to apply elective deductions and tax loss carryovers to the extent anticipated

• CRA will seek to impose transfer pricing penalties (in a manner consistent with penalties charged in the years 2007 through 2009) in addition to interest charges and instalment penalties

• we will be substantially successful in our dispute with CRA and the cumulative tax provision of $87 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date

• IRS will continue to propose adjustments for the years 2010 through 2012 and may propose adjustments for later years

• we will be substantially successful in our dispute with IRS

Material risks that could cause actual results to differ materially

• CRA reassesses us for years 2010 through 2014 using a different methodology than for years 2003 through 2009, or we are unable to utilize elective deductions and loss carryovers to the same extent as anticipated, resulting in the required cash payments 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 outcomes of our dispute with CRA and/or IRS result 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 or IRS not related to transfer pricing

• IRS proposes adjustments for years 2010 through 2014 using a different methodology than for 2009

• we are unable to effectively eliminate all double taxation

FOREIGN EXCHANGE

At March 31, 2015:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.27 (Cdn), up from $1.00 (US) for $1.16 (Cdn) at December 31, 2014. The exchange rate averaged $1.00 (US) for $1.24 (Cdn) over the quarter.

• We had foreign currency forward contracts of $1.5 billion (US) and foreign currency options of $60 million (US) at March 31, 2015. The US currency forward contracts had an average exchange rate of $1.00 (US) for $1.15 (Cdn) and US currency option contracts had an average exchange rate range of $1.00 (US) for $1.25 to $1.31 (Cdn).

• The mark-to-market loss on all foreign exchange contracts was $184 million compared to a $67 million loss at December 31, 2014.

14     CAMECO CORPORATION

Outlook for 2015

Our strategy is to profitably produce at a pace aligned with market signals, while maintaining the ability to respond to conditions as they evolve.

Our outlook for 2015 reflects the expenditures necessary to help us achieve our strategy. Our outlook for uranium revenue, fuel services revenue, consolidated revenue, tax rate and capital expenditures has changed, as explained below. We do not provide an outlook for the items in the table that are marked with a dash.

See 2015 Financial results by segment on page 18 for details.

2015 FINANCIAL OUTLOOK

	CONSOLIDATED	URANIUM	FUEL SERVICES	NUKEM
Production	—	25.3 to 26.3 million lbs	9 to 10 million kgU	—
Sales volume1	—	31 to 33 million lbs	Decrease 5% to 10%	7 to 8 million lbs U3O8
Revenue compared to 20142	Increase up to 5%	Increase up to 5%3	Increase up to 5%	Increase 5% to 10%
Average unit cost of sales (including D&A)	—	Increase 5% to 10%4	Increase 5% to 10%	Increase up to 5%
Direct administration costs compared to 20145	Increase up to 5%	—	—	Decrease up to 5%
Exploration costs compared to 2014	—	Decrease 5% to 10%	—	—
Tax rate	Recovery of 45% to 50%	—	—	Expense of 30% to 35%
Capital expenditures	$405 million	—	—	—

¹  Our 2015 outlook for sales volume in our uranium and NUKEM segments does not include sales between our uranium, fuel services and NUKEM segments.

²  For comparison of our 2015 outlook and 2014 results for revenue in our uranium and NUKEM segments, we do not include sales between our uranium, fuel services and NUKEM segments.

³  Based on a uranium spot price of $38.25 (US) per pound (the Ux spot price as of April 27, 2015), a long-term price indicator of $49.00 (US) per pound (the Ux long-term indicator on April 27, 2015) and an exchange rate of $1.00 (US) for $1.20 (Cdn).

⁴  This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we make discretionary purchases in 2015, then we expect the overall unit cost of sales to increase further.

⁵  Direct administration costs do not include stock-based compensation expenses. See page 11 for more information.

Our outlook for uranium revenue and for fuel services revenue has changed to an increase of up to 5% for each (previously decreases of 5% to 10%, and up to 5% respectively) due to further weakening of the Canadian dollar. As a result consolidated revenue is also now expected to increase by up to 5% (previously a decrease of up to 5%).

We have adjusted our outlook for the tax rate to a recovery of 45% to 50% (previously a recovery of 60% to 65%) due to a change in the distribution of earnings between jurisdictions.

We now expect capital expenditures to be $405 million (previously $370 million). The increase is primarily due to an increase in the cost to modify AREVA’s McClean Lake mill to allow it to operate at 18 million pounds annually, as well as the timing of expenditures on projects at McArthur River and Key Lake. See Uranium 2015 Q1 Updates on page 21 for more information.

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns, sales volumes and revenue can vary significantly. We expect uranium deliveries in the second quarter to be similar to the first quarter, and expect remaining 2015 deliveries to be more heavily weighted to the fourth quarter. However, not all delivery notices have been received to date, which could alter the delivery pattern. Typically, we receive notices six months in advance of the requested delivery date.

2015 FIRST QUARTER REPORT    15

REVENUE AND EARNINGS SENSITIVITY ANALYSIS

For the rest of 2015:

• a change of $5 (US) per pound in both the Ux spot price ($38.25 (US) per pound on April 27, 2015) and the Ux long-term price indicator ($49.00 (US) per pound on April 27, 2015) would change revenue by $88 million and net earnings by $57 million

• a one-cent change in the value of the Canadian dollar versus the US dollar would effectively change revenue by $6 million and net earnings by $1 million, with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

The following table and graph are not forecasts of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table and graph. They are designed to indicate how the portfolio of long-term contracts we had in place on March 31, 2015, as well as Cameco Inc.’s recently signed contract with India’s DAE, 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, 2015 (with the addition of the India contract), and none of the assumptions we list below change.

We intend to update this table and graph each quarter in our MD&A to reflect deliveries made and changes to our contract portfolio. As a result, we expect the table and graph 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
2015		42		46		53		60		67		74		81
2016		40		46		57		68		79		89		98
2017		40		46		57		68		78		88		95
2018		41		47		58		69		79		89		96
2019		41		48		59		69		79		86		93

The table and graph illustrate the mix of long-term contracts in our March 31, 2015 portfolio, and are consistent with our marketing strategy. Both have been updated to reflect deliveries made and contracts entered into up to March 31, 2015 (with the addition of the India contract).

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 lower prices or have low ceiling prices will yield prices that are lower 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:

16     CAMECO CORPORATION

Sales

• sales volumes on average of 29 million pounds per year, with commitment levels in 2015 through 2018 higher than in 2019

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

Deliveries

• deliveries include best estimates of requirements contracts and contracts with volume flex provisions

• we defer a portion of deliveries under existing contracts for 2015

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 19% 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 and graph will be higher.

Liquidity and capital resources

Our financial objective is to make sure we have the cash and debt capacity to fund our operating activities, investments and growth.

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 provide a solid revenue stream for years to come.

We expect to continue investing in maintaining and prudently expanding our production capacity over the next several years. We have a number of alternatives to fund future capital requirements, including using our current cash balances, drawing on our existing credit facilities, entering new credit facilities, using our operating cash flow, 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. However, we expect our cash balances and operating cash flows will meet our anticipated 2015 capital requirements without the need for significant additional funding.

We have an ongoing dispute with CRA regarding our offshore marketing company structure and related transfer pricing arrangements. See page 12 for more information. Until this dispute is settled, we expect to make cash payments to CRA for 50% of the cash taxes payable and the related interest and instalment penalties. We have provided an estimate of the amount and timing of the expected cash taxes payable in the table on page 13. As an alternative to paying cash, we are exploring the possibility of providing security in the form of letters of credit to satisfy our requirements under the tax provisions.

CASH FROM OPERATIONS

Cash from continuing operations was $127 million higher this quarter than in the first quarter of 2014, due largely to a decrease in income taxes paid and a decrease in working capital requirements. Working capital required $70 million less in 2015, largely as a result of an increase in accounts payable during the quarter. Not including working capital requirements, our operating cash flows this quarter were higher by $56 million.

FINANCING ACTIVITIES

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $2.5 billion at March 31, 2015, up $0.1 billion from December 31, 2014. At March 31, 2015, we had approximately $1,067 million outstanding in letters of credit.

Long-term contractual obligations and off-balance sheet arrangements

We had two kinds of off-balance sheet arrangements at March 31, 2015:

• purchase commitments

• financial assurances

There have been no material changes to our long-term contractual obligations or purchase commitments since December 31, 2014. Please see our annual MD&A for more information.

2015 FIRST QUARTER REPORT    17

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, 2015, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2015 to be constrained by them.

FINANCIAL ASSURANCES

At March 31, 2015 our financial assurances totaled $1,067 million compared to $942 million at December 31, 2014. The increase is mainly due to increased requirements for decommissioning letters of credit for Key Lake, as well as exchange rate fluctuations.

BALANCE SHEET

($ MILLIONS)	MAR 31, 2015		DEC 31, 2014		CHANGE
Cash, short-term investments and bank overdraft		558		567		(2	)%
Total debt		1,491		1,491		—
Inventory		1,041		902		15	%

Total cash and short-term investments at March 31, 2015 were $558 million, or 2% lower than at December 31, 2014. Net debt at March 31, 2015 was $933 million.

Total debt remained unchanged from December 31, 2014. See notes 15 and 16 of our audited annual financial statements for more detail.

Total product inventories increased to $1,041 million, including NUKEM’s inventories ($271 million). Uranium inventories increased as sales were lower than production and purchases in the first three months of the year.

Fuel services inventories increased as sales were also lower than production and purchases.

Financial results by segment

Uranium

	THREE MONTHS ENDED MARCH 31
HIGHLIGHTS	2015		2014		CHANGE
Production volume (million lbs)		5.1		5.7		(11	)%
Sales volume (million lbs)1		7.0		6.9		1	%
Average spot price ($US/lb)		38.36		34.94		10	%
Average long-term price ($US/lb)		49.50		48.67		2	%
Average realized price
($US/lb)		43.42		46.60		(7	)%
($Cdn/lb)		52.74		50.58		4	%
Average unit cost of sales ($Cdn/lb) (including D&A)		36.47		33.30		10	%
Revenue ($ millions)1		368		348		6	%
Gross profit ($ millions)		113		119		(5	)%
Gross profit (%)		31		34		(9	)%

¹  Includes sales and revenue between our uranium and NUKEM segments (15,000 pounds in sales and revenue of $0.5 million in Q1 2015, nil in Q1 2014).

FIRST QUARTER

Production volumes this quarter were 11% lower compared to the first quarter of 2014, mainly due to lower production at McArthur River/Key Lake and our ISR operations, partially offset by higher production at Rabbit Lake and production from Cigar Lake. See Uranium 2015 Q1 updates starting on page 21 for more information.

18     CAMECO CORPORATION

Uranium revenues were up 6% due to a 1% increase in sales volumes and a 4% increase in the Canadian dollar average realized price.

The US dollar average realized price decreased by 7% compared to 2014 mainly due to lower prices on fixed price contracts. Our Canadian dollar realized prices this quarter were higher than the first quarter of 2014, primarily as a result of the weakening of the Canadian dollar. In the first quarter of 2015, the exchange rate on the average realized price was $1.00 (US) for $1.21 (Cdn) over the quarter, compared to $1.00 (US) for $1.09 (Cdn) in the first quarter of 2014.

Total cost of sales (including D&A) increased by 11% ($254 million compared to $229 million in 2014). This was mainly the result of a 1% increase in sales volumes and a 13% increase in cash cost of sales. In the first quarter of 2015, total cash cost of sales were $204 million compared to $181 million in the first quarter of 2014 due to a higher volume of material purchases, and increased unit production costs due to lower overall production.

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

The following table shows the costs of produced and purchased uranium incurred in the reporting periods (which are non-IFRS measures, see below table). These costs do not include 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)	2015		2014		CHANGE
Produced
Cash cost		28.05		20.82		35	%
Non-cash cost		12.50		10.55		18	%
Total production cost		40.55		31.37		29	%
Quantity produced (million lbs)		5.1		5.7		(11	)%
Purchased
Cash cost		47.95		42.18		14	%
Quantity purchased (million lbs)		2.7		1.3		108	%
Totals
Produced and purchased costs		43.11		33.38		29	%
Quantities produced and purchased (million lbs)		7.8		7.0		11	%

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 quarters of 2015 and 2014.

2015 FIRST QUARTER REPORT    19

Cash and total cost per pound reconciliation

	THREE MONTHS ENDED MARCH 31
($ MILLIONS)	2015			2014
Cost of product sold		204.2			180.9
Add / (subtract)
Royalties		(13.8	)		(14.2	)
Standby charges		—			(9.3	)
Other selling costs		(1.6	)		(2.4	)
Change in inventories		82.5			18.5
Cash operating costs (a)		271.3			173.5
Add / (subtract)
Depreciation and amortization		50.1			48.3
Change in inventories		14.9			11.9
Total operating costs (b)		336.3			233.7
Uranium produced & purchased (million lbs) (c)		7.8			7.0
Cash costs per pound (a ÷ c)		34.78			24.79
Total costs per pound (b ÷ c)		43.11			33.38

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

	THREE MONTHS ENDED MARCH 31
HIGHLIGHTS	2015		2014		CHANGE
Production volume (million kgU)		2.6		4.0		(35	)%
Sales volume (million kgU)		3.0		1.8		67	%
Average realized price ($Cdn/kgU)		22.11		22.41		(1	)%
Average unit cost of sales ($Cdn/kgU) (including D&A)		19.57		21.36		(8	)%
Revenue ($ millions)		66		40		65	%
Gross profit ($ millions)		8		2		300	%
Gross profit (%)		12		5		140	%

FIRST QUARTER

Total revenue increased by 65% due to a 67% increase in sales volumes.

The total cost of products and services sold (including D&A) increased by 55% ($59 million compared to $38 million in the first quarter of 2014) due to the increase in sales volumes, partially offset by a decrease in the average unit cost of sales. When compared to 2014, the average unit cost of sales was 8% lower due to the mix of fuel services products sold.

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

NUKEM

	THREE MONTHS ENDED MARCH 31
HIGHLIGHTS	2015		2014			CHANGE
Uranium sales (million lbs)1		2.5		0.7			257	%
Average realized price ($Cdn/lb)		38.14		39.81			(4	)%
Cost of product sold (including D&A)		86		35			146	%
Revenue ($ millions)1		97		32			203	%
Gross profit (loss) ($ millions)		11		(3	)		467	%
Gross profit (%)		11		(9	)		222	%

¹  Includes sales and revenue between our uranium, fuel services and NUKEM segments (0.5 million pounds in sales and revenue of $2.5 million in Q1 2015, nil in Q1 2014).

FIRST QUARTER

During the first three months of 2015, NUKEM delivered 2.5 million pounds of uranium, an increase of 1.8 million pounds (257%) due to timing of customer requirements and greater market activity. NUKEM revenues amounted to $97 million as a result of higher deliveries. Average realized prices were slightly lower than those realized in the first quarter of 2014.

20     CAMECO CORPORATION

Gross profit amounted to $11 million, an increase of $14 million compared to the first quarter of 2014. Included in the 2014 loss for the quarter was a $6 million write-down of inventory, as a result of a decline in the spot price during the period compared to a $3 million recovery in 2015. Excluding the effects of inventory adjustments, gross profits would be 8% in the first quarter of 2015 and 9% in the first quarter of 2014.

Our operations

Uranium – production overview

Production in our uranium segment this quarter was 11% lower than the first quarter of 2014, although we remain on target and our 2015 outlook is unchanged. See below for more information.

URANIUM PRODUCTION

	THREE MONTHS ENDED MARCH 31
OUR SHARE (MILLION LBS)	2015		2014		CHANGE			2015 PLAN
McArthur River/Key Lake		2.7		3.8		(29	)%		13.7
Cigar Lake1		0.3		—		—			3.0 – 4.0
Inkai		0.6		0.7		(14	)%		3.0
Rabbit Lake		0.9		0.5		80	%		3.9
Smith Ranch-Highland		0.5		0.5		—			1.4
Crow Butte		0.1		0.2		(50	)%		0.3
Total		5.1		5.7		(11	)%		25.3 – 26.3

¹  Not commercial production – see Cigar Lake update below.

Uranium 2015 Q1 updates

MCARTHUR RIVER/KEY LAKE

Production update

Production for the quarter was 29% lower compared to the same period last year due to several weeks of unplanned mill maintenance to repair the existing calciner and related equipment. Our planned annual production for the operation is unchanged.

Operations update

Construction of the new calciner at Key Lake is ongoing, with commissioning planned for late 2015. The existing calciner circuit will remain in place until operational reliability of the new calciner is achieved. The calciner replacement project was planned in a way that will temporarily allow us to use either calciner, which will help to mitigate risks to our production rate during the commissioning phase.

Licensing and production capacity update

At McArthur River, the CNSC has approved an increase of our licence production limit to 25 million pounds per year (100% basis), which matches the annual mill production licence limit at Key Lake. Provincial approval for 25 million pounds of annual production at McArthur River is the final step in the approval process, and we are currently awaiting a decision.

2015 FIRST QUARTER REPORT    21

The increased production limit at the McArthur River/Key Lake operation aligns with our strategy to maintain the flexibility to respond to market conditions as they evolve, and prepare our operations and projects to respond when the market signals that additional production is needed.

CIGAR LAKE

Production update

The jet boring system at the Cigar Lake mine performed as expected during the first quarter, and we successfully mined 1.9 million pounds of uranium for shipment to the McClean Lake mill. We are continuing to ramp up mine production using two jet boring machines (JBS) and expect to commission the third JBS this year.

The mined ore is routinely transported to the McClean Lake mill, which, during the first quarter, packaged approximately 690,000 pounds (100% basis, 345,000 pounds our share) and remains on track to achieve the annual production target of 6 million to 8 million packaged pounds (100% basis).

As of April 25, a total of about 2.7 million pounds of uranium has been extracted from the mine, and a total of about 1.5 million pounds (100% basis) has been packaged at the McClean Lake mill in 2015.

Commercial production

Commercial production is achieved when management determines that the mine is able to produce at a consistent or sustainably increasing level. Once we have declared commercial production at Cigar Lake, we will begin depreciating the assets, contributing to an increase in our overall production costs (non-cash), as indicated in our 2015 outlook.

Rampup schedule

We expect Cigar Lake to produce between 6 million and 8 million packaged pounds in 2015; our share is 3 million to 4 million pounds. As we ramp up production to 18 million pounds (100% basis) by 2018, volumes may not be linear year-to-year, but will vary based on our operational experience. To ensure the most efficient operation of the mine and mill throughout the year, we expect to continually manage ore supply and, therefore, may halt and resume mining several times during a quarter without impacting planned annual production.

Mill update

AREVA has indicated good progress in the ramp up of the McClean mill, with feed grades exceeding 25% U₃O₈, and an output well above historical mill production levels. To allow the McClean Lake mill to reach full production of 18 million pounds annually, AREVA now estimates that our share of expenditures related to the mill modifications will be about $80 million in 2015 (previously $60 to $70 million (our share) in 2015), and advises additional expenditures will also be required after 2015. The increase in 2015 expenditures is due to larger quantities of piping, electrical, instrumentation, and related labour, identified upon completion of detailed engineering. AREVA is currently preparing an updated estimate of the cost to complete the mill modifications.

Caution about forward-looking information relating to Cigar Lake

This discussion of our expectations for Cigar Lake, including our plan for 6 million to 8 million packaged pounds (100%) in 2015, 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.

INKAI

Production update

Production in the first quarter was 14% lower compared to the same period of 2014, but remains aligned with the current 2015 mine plan. Inkai is on target to produce 5.2 million pounds (100% basis) this year.

22     CAMECO CORPORATION

Block 3

The Ministry of Energy of the Republic of Kazakhstan has issued a letter to JV Inkai approving the extension of the period for Block 3 deposit evaluation by three years to July 13, 2018, provided the design document is approved in accordance with the established legislation order before June 13, 2015.

RABBIT LAKE

Production update

Production for the quarter was 80% higher than the same period last year, mainly due to better ore grades and the timing of production stopes. We typically experience large variations in mill production from quarter to quarter, and we remain on track to achieve our annual production target.

SMITH RANCH-HIGHLAND AND CROW BUTTE

Production update

At our US operations, as expected, total production for the quarter was 14% lower than the first quarter of 2014 due to a declining head grade at Crow Butte, where there are no new wellfields being developed under the current mine plan.

Fuel services 2015 Q1 updates

PORT HOPE CONVERSION SERVICES

CAMECO FUEL MANUFACTURING INC. (CFM)

Production update

Fuel services produced 2.6 million kgU in the first quarter, 35% lower than the same period last year, primarily due to the reduced volumes attributable to the early termination of the SFL contract in 2014. We decreased our production target in 2015 to between 9 million and 10 million kgU, so quarterly production is expected to be lower than comparable periods in 2014.

Labour Relations

The current collective bargaining agreement for our unionized employees at CFM expires on June 1, 2015. We began preparing for the collective bargaining process during the first quarter.

Qualified persons

The technical and scientific information discussed in this MD&A 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

• David Bronkhorst, vice-president, mining and technology, Cameco

CIGAR LAKE

• Les Yesnik, general manager, Cigar Lake, Cameco

INKAI

• Darryl Clark, general director, JV Inkai

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.

2015 FIRST QUARTER REPORT    23

Controls and procedures

As of March 31, 2015, 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, 2015, the CEO and CFO concluded that:

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

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

There has been no change in our internal control over financial reporting during the quarter ended March 31, 2015 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 are not yet effective for the period ended March 31, 2015, and have not been applied in preparing the interim financial statements. The following standards and amendments to existing standards have been published and are mandatory for our accounting periods beginning on or after January 1, 2016, unless otherwise noted. We do not intend to early adopt any of the following amendments to existing standards, and we do not expect the amendments to have a material impact on our financial statements.

IAS16, Property, Plant and Equipment (IAS 16) and IAS 38, Intangible Assets (IAS 38) – In May 2014, the IASB issued amendments to IAS16 and IAS 38. The amendments are to be applied prospectively. The amendments clarify the factors to be considered in assessing the technical or commercial obsolescence and the resulting depreciation period of an asset and state that a depreciation method based on revenue, is not appropriate.

IFRS 11, Joint Arrangements (IFRS 11) – In May 2014, the IASB issued amendments to IFRS 11. The amendments in IFRS 11 are to be applied prospectively. The amendments clarify the accounting for the acquisition of interests in joint operations and require the acquirer to apply the principles of business combinations accounting in IFRS 3 Business Combinations.

IFRS 10, Consolidated Financial Statements (IFRS 10) and IAS 28, Investments in Associate and Joint Ventures (IAS 28) – In September 2014, the IASB issued amendments to IFRS 10 and IAS 28. The amendments provide clarification on the recognition of gains or losses upon the sale or contribution of assets between an investor and its associate or joint venture.

IFRS 5, Non-Current Assets Held for Sale and Discontinued Operations (IFRS 5) – In September 2014, the IASB issued amendments to IFRS 5. The amendments are to be applied prospectively, with earlier application permitted. Assets are generally disposed of either through sale or through distribution to owners. The amendments clarify the application of IFRS 5 when changing from one of these disposal methods to the other.

IFRS 7, Financial Instruments: Disclosures (IFRS 7) – In September 2014, the IASB issued amendments to IFRS 7. The amendments in IFRS 7 are to be applied retrospectively, with earlier application permitted. The amendments clarify the disclosure required for any continuing involvement in a transferred asset that has been derecognized. The amendments also provide guidance on disclosures regarding the offsetting of financial assets and financial liabilities in interim financial reports.

IAS 34 Interim Financial Reporting (IAS 34) – In September 2014, the IASB issued amendments to IAS 34. The amendments are to be applied retrospectively, with earlier application permitted. The amendments provide additional guidance on interim disclosures and whether they are provided in the interim financial statements or incorporated by cross-reference between the interim financial statements and other financial disclosures.

24     CAMECO CORPORATION

IFRS 15, Revenue from Contracts with Customers (IFRS 15) – In May 2014, the IASB issued IFRS 15. IFRS 15 is effective for periods beginning on or after January 1, 2017 and is to be applied retrospectively. IFRS 15 clarifies the principles for recognizing revenue from contracts with customers. The extent of the impact of adoption of IFRS 15 has not yet been determined.

IFRS 9, Financial Instruments (IFRS 9) – In July, 2014, the International Accounting Standards Board (IASB) issued IFRS 9. IFRS 9 replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The basis of classification depends on the entity’s business model and the contractual cash flow characteristics of the financial asset or liability. It also introduces additional changes relating to financial liabilities and aligns hedge accounting more closely with risk management.

IFRS 9 is effective for annual periods beginning on or after January 1, 2018, with early adoption of the new standard permitted. We do not intend to early adopt IFRS 9. The extent of the impact of adoption of IFRS 9 has not yet been determined.

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