Exhibit 99.2

Management’s discussion and analysis

for the quarter ended March 31, 2014

FIRST QUARTER UPDATE	4
CONSOLIDATED FINANCIAL RESULTS	7
OUTLOOK FOR 2014	13
LIQUIDITY AND CAPITAL RESOURCES	14
FINANCIAL RESULTS BY SEGMENT
URANIUM	16
FUEL SERVICES	19
NUKEM	19
OUR OPERATIONS	20
URANIUM 2014 Q1 UPDATES	20
FUEL SERVICES 2014 Q1 UPDATES	22
QUALIFIED PERSONS	22
ADDITIONAL INFORMATION	22

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, 2014 (interim financial statements). The information is based on what we knew as of April 28, 2014 and updates the annual MD&A included in our 2013 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, 2013 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.

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 2014 and future global uranium supply, consumption, demand and number of new reactors, including the discussion under the heading Uranium market update

• our expectations for uranium deliveries in the second quarter and uranium sales for the balance of 2014

• the discussion of our expectations relating to our tax dispute with Canada Revenue Agency (CRA), including our estimate of the amount and timing of expected cash taxes and transfer pricing penalties payable to CRA

• our consolidated outlook for the year and the outlook for our operating segments for 2014

• our expectation that existing cash balances and operating cash flows would be sufficient to meet our anticipated 2014 capital requirements without the need for any significant additional funding

• our expectation that our operating and investment activities in 2014 will not be constrained by the financial covenants in our unsecured revolving credit facility

• our uranium price sensitivity analysis

• our future plans and expectations for each of our uranium operating properties and fuel services operating sites

• our plan for 2 million to 3 million packaged pounds (100% basis) in 2014 from milling Cigar Lake ore at AREVA’s McClean Lake mill

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 dispute with CRA

• 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 in a developing country where we operate

• 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 and conversion suppliers fail to fulfil delivery commitments

• our Cigar Lake 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, or any difficulties with the McClean Lake mill modifications or commissioning or milling of Cigar Lake ore, or our inability to acquire any of the required jet boring equipment

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

• 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 (including an inability to renew agreements with unionized employees at McArthur River and Key Lake), 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 on page 18, Price sensitivity analysis: uranium

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

• our expectations about the outcome of the dispute with CRA

• 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 Cigar Lake mining and production plans succeed, including, including the additional jet boring equipment is acquired on schedule, the jet boring mining method works as anticipated and the deposit freezes as planned

• mill modifications and commissioning of the McClean Lake mill are completed as planned and the mill is able to process Cigar Lake ore as expected, including our expectation of processing 2 million to 3 million packaged pounds (100% basis) in 2014

• our McArthur River development, mining and production plans succeed

• 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 (including an inability to renew agreements with unionized employees at McArthur River and Key Lake), 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

2014 FIRST QUARTER REPORT      3

Our strategy

Our strategy is to profitably produce at a pace aligned with market signals, while maintaining the flexibility to respond to market conditions as they evolve. We remain focused on taking advantage of the long-term growth we see coming in our industry to increase long-term shareholder value.

We plan to:

• carry out all of our business with a focus on safety, people and the environment

• 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 bring on and ramp up production at Cigar Lake

• manage the rest of our production facilities and potential 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

• manage and allocate capital in a way that balances growing the long-term value of the business and returns to shareholders, while maintaining a strong balance sheet and our investment grade rating

You can read more about our strategy in our 2013 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 has been 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 our operating earnings from BPLP, and the financial impact of the sale, 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)	2014		2013		CHANGE
Revenue		419		444		(6	)%
Gross profit		108		95		14	%
Net earnings attributable to equity holders		131		9		1,356	%
$ per common share (diluted)		0.33		0.02		1,550	%
Adjusted net earnings (non-IFRS, see page 7)		36		27		33	%
$ per common share (adjusted and diluted)		0.09		0.07		29	%
Cash provided by continuing operations (after working capital changes)		7		241		(97	)%

FIRST QUARTER

Net earnings attributable to equity holders (net earnings) this quarter were $131 million ($0.33 per share diluted) compared to $9 million ($0.02 per share diluted) in the first quarter of 2013. In addition to the items noted below, our net earnings were affected by a gain on the sale of our interest in BPLP of $127 million, offset by mark-to-market losses on foreign exchange derivatives.

4      CAMECO CORPORATION

On an adjusted basis, our earnings this quarter were $36 million ($0.09 per share diluted) compared to $27 million ($0.07 per share diluted) (non-IFRS measure, see page 7) in the first quarter of 2013. The change was mainly due to higher earnings from our uranium segment based on higher sales volumes and higher realized prices, partially offset by 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.

See Financial results by segment on page 16 for more detailed discussion.

Operations update

		THREE MONTHS ENDED MARCH 31
HIGHLIGHTS		2014			2013		CHANGE
Uranium	Production volume (million lbs)		5.7			5.9		(3	)%
	Sales volume (million lbs)		6.9			5.1		35	%
	Average realized price ($US/lb)		46.60			48.42		(4	)%
	($Cdn/lb)		50.58			48.25		5	%
	Revenue ($ millions)		348			247		41	%
	Gross profit ($ millions)		119			84		42	%
Fuel services	Production volume (million kgU)		4.0			4.7		(15	)%
	Sales volume (million kgU)		1.8			3.4		(47	)%
	Average realized price ($Cdn/kgU)		22.41			19.60		14	%
	Revenue ($ millions)		40			66		(39	)%
	Gross profit ($ millions)		2			11		(82	)%
NUKEM1	Sales volume U3O8 (million lbs)		0.7			2.3		(70	)%
	Average realized price uranium ($Cdn/lb)		39.81			43.64		(9	)%
	Revenue ($ millions)		32			131		(76	)%
	Gross profit (loss) ($ millions)		(3	)		4		(175	)%

¹  See NUKEM on page 19 for details of the purchase price allocation.

Production in our uranium segment this quarter was 3% lower compared to the first quarter of 2013, mainly due to lower production at Rabbit Lake. See Uranium 2014 Q1 updates starting on page 20 for more information.

Key highlights:

• we began mine production at Cigar Lake and started to ship ore from the mine to the McClean Lake mill to await processing

• although the McClean Lake mill will not begin processing Cigar Lake ore by the end of the second quarter, we continue to plan for 2 million to 3 million packaged pounds (100% basis) in 2014.

• At McArthur River, the Canadian Nuclear Safety Commission (CNSC) approved an increase of our licence production limit to 21 million pounds (100% basis) per year from the mine. See Uranium Q1 2014 updates on page 20 for more information.

Production in our fuel services segment was 15% lower this quarter than in the first quarter of 2013 due to lower planned annual production in 2014.

Uranium market update

In the first quarter of 2014, market conditions continued along the same trend as in 2013. Contracted volumes remained low, putting further downward pressure on both spot and long-term uranium prices. On the supply side, production cutbacks and project deferrals have contributed positively to long-term fundamentals, but for the near term, the market continues to be adequately supplied. Utilities remain well covered and we expect little improvement over the near to medium term.

2014 FIRST QUARTER REPORT      5

While there has been no fundamental change to market conditions, there have been developments that solidify the positive long-term outlook, including the approval of a new energy policy in Japan that confirms nuclear power will remain an important electricity source for the country. In addition, the Nuclear Regulatory Authority continued to clarify the process for utilities to begin restarting the country’s idled nuclear reactors. While the initial restarts will be a positive development, we expect it will take some time for a significant number of reactors to resume operations, and for the inventory that has built up since 2011 to clear.

Long-term fundamentals remain positive as nuclear growth continues to progress around the world. Approximately 70 new reactors are under construction, and we expect a net increase of 93 reactors over the next 10 years, which is expected to drive an increase in annual uranium consumption from today’s 170 million pounds to about 240 million pounds. 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 and future global uranium supply, demand and consumption, 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 2014		DEC 31 2013		MAR 31 2013		DEC 31 2012
Uranium ($US/lb U3O8) 1
Average spot market price		34.00		34.50		42.25		43.38
Average long-term price		46.00		50.00		56.50		56.50
Fuel services ($US/kgU as UF6)1
Average spot market price
North America		7.63		8.50		10.50		10.50
Europe		8.00		9.00		11.00		11.00
Average long-term price
North America		16.00		16.00		16.75		16.75
Europe		17.00		17.00		17.25		17.25

Note: the industry does not publish UO₂ prices.

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

On the spot market, where purchases call for delivery within one year, the volume reported for the first quarter of 2014 was approximately 10 million pounds. This compares to approximately 16 million pounds in the first quarter of 2013.

At the end of the quarter, the average reported spot price was $34.00 (US) per pound, and the average reported long-term price declined to $46.00 (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 25, 2014, we had:

• 395,759,872 common shares and one Class B share outstanding

• 9,152,105 stock options outstanding, with exercise prices ranging from $19.37 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.

6      CAMECO CORPORATION

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)	2014		2013		CHANGE
Revenue		419		444		(6	)%
Gross profit		108		95		14	%
Net earnings attributable to equity holders		131		9		1,356	%
$ per common share (basic)		0.33		0.02		1,550	%
$ per common share (diluted)		0.33		0.02		1,550	%
Adjusted net earnings (non-IFRS, see page 7)		36		27		33	%
$ per common share (adjusted and diluted)		0.09		0.07		29	%
Cash provided by continuing operations (after working capital changes)		7		241		(97	)%

Net earnings

Net earnings attributable to equity holders (net earnings) this quarter were $131 million ($0.33 per share diluted) compared to $9 million ($0.02 per share diluted) in the first quarter of 2013. In addition to the items noted below, our net earnings were affected by a gain on the sale of our interest in BPLP of $127 million, offset by mark-to-market losses on foreign exchange derivatives.

On an adjusted basis, our earnings this quarter were $36 million ($0.09 per share diluted) compared to $27 million ($0.07 per share diluted) (non-IFRS measure, see page 7) in the first quarter of 2013. This was mainly due to higher earnings from our uranium segment based on higher sales volumes and higher realized prices, partially offset by 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 been adjusted for pre-tax adjustments on derivatives, NUKEM purchase price inventory write-down, impairment charge on non-producing property, income taxes on adjustments, 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 table on the following page reconciles adjusted net earnings with our net earnings.

2014 FIRST QUARTER REPORT      7

	THREE MONTHS ENDED MARCH 31
($ MILLIONS)	2014			2013
Net earnings attributable to equity holders		131			9
Adjustments
Adjustments on derivatives1 (pre-tax)		44			25
Income taxes on adjustments		(12	)		(7	)
Gain on interest in BPLP (after tax)		(127	)		—
Adjusted net earnings		36			27

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

($ MILLIONS)		THREE MONTHS ENDED MARCH 31
Adjusted net earnings – 2013			27
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		29
	Lower realized prices ($US)		(12	)
	Foreign exchange impact on realized prices		28
	Higher costs		(10	)
	Hedging effects		(17	)
	change – uranium		18
Fuel services	Lower sales volume		(5	)
	Higher realized prices ($Cdn)		5
	Higher costs		(9	)
	Hedging effects		(1	)
	change – fuel services		(10	)
NUKEM	Gross loss		(7	)
	change – NUKEM		(7	)
Other changes
Lower administration expenditures			11
Lower exploration expenditures			6
Lower income taxes			12
Contract cancellation fee			(18	)
Loss on equity-accounted investments			(9	)
Foreign exchange			10
Other			(4	)
Adjusted net earnings – 2014			36

See Financial results by segment on page 16 for more detailed discussion.

8      CAMECO CORPORATION

Quarterly trends

HIGHLIGHTS	2014		2013									2012
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q1		Q4		Q3		Q2			Q1		Q41		Q31		Q21
Revenue		419		977		597		421			444		846		296		282
Net earnings attributable to equity holders		131		64		211		34			9		41		79		5
$ per common share (basic)		0.33		0.16		0.53		0.09			0.02		0.10		0.20		0.01
$ per common share (diluted)		0.33		0.16		0.53		0.09			0.02		0.10		0.20		0.01
Adjusted net earnings (non-IFRS, see page 7)		36		150		208		61			27		233		49		31
$ per common share (adjusted and diluted)		0.09		0.38		0.53		0.14			0.07		0.59		0.12		0.08
Earnings from continuing operations		4		29		164		34			8		7		47		(30	)
$ per common share (basic)		0.01		0.07		0.41		0.08			0.02		0.02		0.12		(0.08	)
$ per common share (diluted)		0.01		0.07		0.41		0.08			0.02		0.02		0.12		(0.08	)
Cash provided by continuing operations (after working capital changes)		7		163		154		(33	)		241		281		43		(128	)

¹  Our quarterly results have been revised in accordance with IFRS 11 – Joint Arrangements and IAS 19 – Employee Benefits.

Key things to note:

• our financial results are strongly influenced by the performance of our uranium segment, which accounted for 83% of consolidated revenues in the first quarter of 2014

• 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 7 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	2014			2013												2012
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q1			Q4			Q3			Q2			Q1			Q42			Q32			Q22
Net earnings attributable to equity holders		131			64			211			34			9			41			79			5
Adjustments
Adjustments on derivatives1 (pre-tax)		44			36			(41	)		36			25			33			(40	)		35
NUKEM purchase price inventory write-down		—			(3	)		17			—			—			—			—			—
Impairment charge on non-producing property		—			70			15			—			—			168			—			—
Income taxes on adjustments		(12	)		(17	)		6			(9	)		(7	)		(9	)		10			(9	)
Gain on sale of BPLP (after tax)		(127	)		—			—			—			—			—			—			—
Adjusted net earnings (non-IFRS, see page 7)		36			150			208			61			27			233			49			31

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.

²  Our quarterly results have been revised in accordance with IFRS 11 – Joint Arrangements and IAS 19 – Employee Benefits.

2014 FIRST QUARTER REPORT      9

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 has been 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)	2014			2013
Share of earnings from BPLP and related entities		—			1.2
Tax expense		—			(0.3	)
		—			0.9
Gain on disposal of BPLP and related entities		144.9			—
Tax expense on disposal		(17.7	)		—
		127.2			—
Net earnings from discontinued operations		127.2			0.9

Corporate expenses

ADMINISTRATION

($ MILLIONS)	THREE MONTHS ENDED MARCH 31
	2014		2013		CHANGE
Direct administration		38		44		(14	)%
Restructuring charges		—		3		(100	)%
Stock-based compensation		7		9		(22	)%
Total administration		45		56		(20	)%

Direct administration costs were $6 million lower for the first quarter compared to the same period last year due to the restructuring activities undertaken in 2013.

Stock based compensation was $2 million lower than in 2013 due to a change in the compensation program.

EXPLORATION

In the first quarter, uranium exploration expenses were $14 million, a decrease of $6 million compared to the first quarter of 2013 as a result of decreased activity in Australia and a more focused effort on our core projects in Saskatchewan.

INCOME TAXES

We recorded an income tax recovery of $45 million in the first quarter of 2014 compared to a recovery of $28 million in the first quarter of 2013. The change in the net recovery was in part due to a change in the distribution of earnings between jurisdictions. In 2014, we recorded losses of $193 million in Canada compared to $130 million in 2013, while earnings in foreign jurisdictions increased to $152 million from $109 million. The tax rate in Canada is higher than the average of the rates in the foreign jurisdictions in which our subsidiaries operate.

On an adjusted basis, we recorded an income tax recovery of $34 million this quarter compared to a recovery of $21 million in the first quarter of 2013 due to lower pre-tax adjusted earnings and a change in the distribution of earnings between jurisdictions.

10      CAMECO CORPORATION

	THREE MONTHS ENDED MARCH 31
($ MILLIONS)	2014			2013
Pre-tax adjusted earnings1
Canada2		(151	)		(106	)
Foreign		152			111
Total pre-tax adjusted earnings		1			5
Adjusted income taxes1
Canada2		(37	)		(26	)
Foreign		3			5
Adjusted income tax expense (recovery)		(34	)		(21	)

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 7).

CRA DISCLOSURE

As previously reported, since 2008, the Canada Revenue Agency (CRA) has disputed the offshore marketing company structure and related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2008 tax returns. We 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. We are updating our disclosure on the CRA case to reflect the CRA’s intention to accelerate the frequency of reassessments.

Transfer pricing is a complex area of tax law, and it is difficult to predict the outcome of a case like ours as there are only a handful of reported court decisions on transfer pricing in Canada. However, tax authorities generally test two things:

• the governance (structure)

• the price

The majority of our customers are located outside Canada and we established an offshore marketing subsidiary. This subsidiary entered into intercompany purchase and sales agreements as well as uranium supply agreements with third parties. We have arm’s-length transfer price arrangements in place, which expose both parties to the risks and the rewards accruing to them under this portfolio of purchase and sales contracts.

With respect to the contract prices, they are generally comparable to those established in sales contracts between arm’s-length buyers and sellers entered into at that time. We have recorded a cumulative tax provision of $75 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 to March 31, 2014.

We are confident that we will be successful in our case; however, for the years 2003 through 2008, CRA issued notices of reassessment for approximately $2.0 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $590 million. The Canadian Income Tax Act includes provisions that require larger companies like us to pay 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 been required to pay a net amount of $117 million to CRA, which includes the amounts shown in the table below.

YEAR ($ MILLIONS)	CASH TAXES		INTEREST AND INSTALMENT PENALTIES		TRANSFER PRICING PENALTIES		TOTAL
Prior to 2013		—		13		—		13
2013		1		9		36		46
2014		28		30		—		58
Total		29		52		36		117

2014 FIRST QUARTER REPORT      11

Using the methodology we believe CRA will continue to apply, and including the $2.0 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $5.7 billion of additional income as taxable in Canada for the years 2003 through 2013, which would result in a related tax expense of approximately $1.6 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2007. As a result, we estimate that cash taxes and transfer pricing penalties would be between $1.25 billion and $1.3 billion. In addition, we estimate there would be interest and instalment penalties applied that would be material to us. We would be responsible for remitting 50% of the cash taxes and transfer pricing penalties (between $625 million and $650 million), plus related interest and instalment penalties assessed, which would be material to us.

Under the Canadian federal and provincial tax legislation, the amount required to be remitted 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 indicated that they intend to accelerate the frequency of reassessments related to the transfer pricing adjustments. Their audit of 2009 has been completed and we have received proposed adjustments to 2009 taxable income which are calculated in a manner consistent with prior years. We expect the reassessment for the 2009 taxation year to be issued in the second quarter of 2014, rather than in the fourth quarter as was the case for previous years. In addition, we believe CRA may complete their audit of 2010 and issue the resulting reassessment in 2014 as well. The estimated amounts summarized in the table below reflect this expected accelerated schedule.

$ MILLIONS	2003 - 2013		20142		2015 - 2016		2017 - 2023		TOTAL
50% of cash taxes and transfer pricing penalties payable in the period1		37		115 - 135		450 - 475		0 - 25		625 - 650

¹ These amounts do not include interest and instalment penalties, which totaled approximately $52 million to March 31, 2014.

²  These amounts include $28 million already paid in 2014.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to CRA, including the $117 million already paid to date.

The case on the 2003 reassessment is expected to go to trial in 2015. If this timing is adhered to, we expect to have a Tax Court decision by 2016.

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, including the amounts of future additional taxable income, additional tax expense, cash taxes payable, transfer pricing penalties, and interest and possible instalment penalties thereon and related remittances, and timing of a Tax Court decision, 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 2009 through 2013 using a similar methodology as for the years 2003 through 2008, and the reassessments will be issued on an accelerated basis as described above

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

• CRA will seek to impose transfer pricing penalties (10% of the income adjustment) in addition to interest charges and instalment penalties

• we will be substantially successful in our dispute with CRA and the cumulative tax provision of $75 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 2009 through 2013 using a different methodology than for years 2003 through 2008, 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 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

12      CAMECO CORPORATION

FOREIGN EXCHANGE

At March 31, 2014:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.11 (Cdn), up from $1.00 (US) for $1.06 (Cdn) at December 31, 2013. The exchange rate averaged $1.00 (US) for $1.10 (Cdn) over the quarter.

• We had foreign currency contracts of $1.7 billion (US) and €45 million at March 31, 2014. The mark-to-market loss on all foreign exchange contracts was $57 million compared to a $27 million loss at December 31, 2013. The average exchange rate for USD currency contracts was $1.00 (US) for $1.08 (Cdn) and €1.00 for $1.36 (US) for EUR currency contracts.

Outlook for 2014

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 2014 reflects the expenditures necessary to help us achieve our strategy. Our outlook for uranium revenue and consolidated revenue, as well as our production outlook for fuel services has changed, and is explained below. We do not provide an outlook for the items in the table that are marked with a dash.

See 2014 Financial results by segment on page 16 for details.

2014 FINANCIAL OUTLOOK

	CONSOLIDATED	URANIUM		FUEL SERVICES		NUKEM
Production	—		23.8 to 24.3 million lbs		12 to 13 million kgU		—
Sales volume	—		31 to 33 million lbs		Decrease 5% to 10%		9 to 11 million lbs U3O8
Revenue compared to 2013	Increase 5% to 10%		Increase 5% to 10%1		Decrease 5% to 10%		Increase 0% to 5%
Average unit cost of sales (including D&A)	—		Increase 0% to 5%2		Increase 0% to 5%		Increase 0% to 5%
Direct administration costs compared to 20133	Increase 0% to 5%		—		—		Increase 0% to 5%
Exploration costs compared to 2013	—		Decrease 35% to 40%		—		—
Tax rate	Recovery of 30% to 35%		—		—		Expense of 30% to 35%
Capital expenditures	$495 million		—		—		—

¹  Based on a uranium spot price of $30.75 (US) per pound (the Ux spot price as of April 28, 2014), a long-term price indicator of $45.00 (US) per pound (the Ux long-term indicator on April 28, 2014) and an exchange rate of $1.00 (US) for $1.08 (Cdn).

²  This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we make discretionary purchases in 2014, then we expect the overall unit cost of sales to increase further.

³  Direct administration costs do not include stock-based compensation expenses. See page 10 for more information.

We now expect an increase of 5% to 10% for sales revenue in our uranium segment (previously an increase of up to 5%) due to the impact of the strengthening US dollar. The consolidated revenue will increase by 5% to 10% as well (previously up to 5%) due to the impact of the uranium revenue increase.

We now expect production in our fuel services segment to be 12 million to 13 million kgU (down from previously reported 13 million to 14 million kgU) due to the cancellation of our toll conversion contract with SFL, which was included in the previously reported production amount.

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 our uranium deliveries for the second quarter will be greater than the first quarter. Uranium sales are relatively balanced for the remainder of 2014. 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.

2014 FIRST QUARTER REPORT      13

SENSITIVITY ANALYSIS

For the rest of 2014:

• a change of $5 (US) per pound in both the Ux spot price ($30.75 (US) per pound on April 28, 2014) and the Ux long-term price indicator ($45.00 (US) per pound on April 28, 2014) would change revenue by $58 million and net earnings by $35 million

• a one-cent change in the value of the Canadian dollar versus the US dollar would effectively change revenue by $7 million and adjusted net earnings by $3 million, with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact. This sensitivity is based on an exchange rate of $1.00 (US) for $1.00 (Cdn).

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 expect our existing cash balances and operating cash flows will meet our anticipated 2014 capital requirements without the need for significant additional funding.

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.

We have an ongoing dispute with CRA regarding our offshore marketing company structure and related transfer pricing arrangements. See page 11 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 12.

CASH FROM CONTINUING OPERATIONS

Cash from continuing operations was $234 million lower this quarter than in the first quarter of 2013, due largely to an increase in income taxes paid and an increase in working capital requirements. Working capital required $178 million more in 2014, largely as a result of an increase in uranium inventories during the quarter. Not including working capital requirements, our operating cash flows this quarter were lower by $55 million.

INVESTING ACTIVITIES

On January 31, 2014, we announced the sale of our 31.6% limited partnership interest in BPLP and related entities for $450 million. The sale closed on March 27, 2014 and has been accounted for effective January 1, 2014.

DEBT

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $2.2 billion at March 31, 2014, unchanged from December 31, 2013. At March 31, 2014, we had approximately $808 million outstanding in letters of credit.

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, 2014, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2014 to be constrained by them.

LONG-TERM CONTRACTUAL OBLIGATIONS AND OFF-BALANCE SHEET ARRANGEMENTS

We had two kinds of off-balance sheet arrangements at March 31, 2014:

• purchase commitments

• financial assurances

14      CAMECO CORPORATION

Our long-term contractual obligations do not include our sales commitments. Please see our annual MD&A for more information.

PURCHASE COMMITMENTS

MARCH 31 ($ MILLIONS)	2014		2015 AND 2016		2017 AND 2018		2019 AND BEYOND		TOTAL
Purchase commitments1		348		628		189		394		1,559

¹  Denominated in US dollars, converted to Canadian dollars as of March 31, 2014 at the rate of $1.11.

During the first quarter, our purchase commitments increased due to the signing of new long-term purchase commitments, which we believe will be beneficial for us as they have been in the past. The increase was partially offset by the termination of our agreement with SFL.

As of March 31, 2014, we had commitments of about $1.6 billion (Cdn) for the following:

• approximately 29 million pounds of U₃O₈ equivalent from 2014 to 2028

• approximately 7 million kgU as UF₆ in conversion services from 2014 to 2017, including about 4 million kgU to complete our 2014 obligations to SFL under the terminated agreement

• over 1.2 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-Western supplier

The SWU supplier does not have the right to terminate their agreements other than pursuant to customary event of default provisions.

FINANCIAL ASSURANCES

At March 31, 2014 our financial assurances totaled $808 million compared to $849 million at December 31, 2013. The decrease is mainly due to the sale of BPLP, which eliminates our commitment for financial guarantees on its behalf. These guarantees were estimated at $58 million at the end of 2013.

BALANCE SHEET

($ MILLIONS)	MAR 31, 2014		DEC 31, 2013		CHANGE
Cash, short-term investments and bank overdraft		467		188		148	%
Total debt		1,334		1,344		(1	)%
Inventory		1,041		913		14	%

Total cash and short-term investments at March 31, 2014 were $467 million, or 148% higher than at December 31, 2013 due to completion of the sale of BPLP in March. Net debt at March 31, 2014 was $867 million.

Total debt decreased by $10 million to $1,334 million at March 31, 2014. Of this total, $40 million was classified as current, down $10 million compared to December 31, 2013. See notes 16 and 17 of our audited annual financial statements for more detail.

Total product inventories increased to $1,041 million, including NUKEM’s inventories ($266 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.

2014 FIRST QUARTER REPORT      15

Financial results by segment

Uranium

	THREE MONTHS ENDED MARCH 31
HIGHLIGHTS	2014		2013		CHANGE
Production volume (million lbs)		5.7		5.9		(3	)%
Sales volume (million lbs)		6.9		5.1		35	%
Average spot price ($US/lb)		34.94		42.71		(18	)%
Average long-term price ($US/lb)		48.67		56.50		(14	)%
Average realized price
($US/lb)		46.60		48.42		(4	)%
($Cdn/lb)		50.58		48.25		5	%
Average unit cost of sales ($Cdn/lb) (including D&A)		33.30		31.90		4	%
Revenue ($ millions)		348		247		41	%
Gross profit ($ millions)		119		84		42	%
Gross profit (%)		34		34		—

FIRST QUARTER

Production volumes this quarter were 3% lower compared to the first quarter of 2013 due, mainly, to lower production at Rabbit Lake. See Uranium 2014 Q1 updates starting on page 20 for more information.

Uranium revenues were up 41% due to a 35% increase in sales volumes and a 5% increase in the Canadian dollar average realized price. Sales in the first quarter were higher than anticipated at the end of 2013 due to a change in the timing of deliveries during the quarter, which can vary significantly and are driven by customer requests.

Our realized prices this quarter were higher than the first quarter of 2013, primarily as a result of the weakening of the Canadian dollar. In the first quarter of 2014, the exchange rate on the average realized price was $1.00 (US) for $1.09 (Cdn) over the quarter, compared to $1.00 (US) for $1.00 (Cdn) in the first quarter of 2013.

Total cost of sales (including D&A) increased by 40% ($229 million compared to $163 million in 2013). This was mainly the result of a 35% increase in sales volumes and an increase in non-cash costs. In the first quarter of 2014, total non-cash costs were $48 million compared to $20 million in the first quarter of 2013 due to the completion of a number of capital projects at our various production facilities. Upon project completion, we begin to depreciate the asset, which increases the non-cash portion of our production costs.

Additionally, in the first quarter, our cost of purchased material was higher than the average spot price for the quarter and higher than in the first quarter of 2013. We had back-to-back purchase and sale arrangements that, while profitable, required we purchase material at a price higher than the current spot price.

The net effect was a $35 million increase in gross profit for the quarter.

The table on the following page 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 selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.

16      CAMECO CORPORATION

	THREE MONTHS ENDED MARCH 31
($CDN/LB)	2014		2013		CHANGE
Produced
Cash cost		20.82		19.12		9	%
Non-cash cost		10.55		8.44		25	%
Total production cost		31.37		27.56		14	%
Quantity produced (million lbs)		5.7		5.9		(3	)%
Purchased
Cash cost		42.18		33.44		26	%
Quantity purchased (million lbs)		1.3		2.3		(43	)%
Totals
Produced and purchased costs		33.38		29.21		14	%
Quantities produced and purchased (million lbs)		7.0		8.2		(15	)%

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 2014 and 2013.

CASH AND TOTAL COST PER POUND RECONCILIATION

	THREE MONTHS ENDED MARCH 31
($ MILLIONS)	2014			2013			CHANGE
Cost of product sold		180.9			144.0			26	%
Add / (subtract)
Royalties		(14.2	)		(14.4	)		(1	)%
Standby charges		(9.3	)		(8.1	)		15	%
Other selling costs		(2.4	)		2.8			(186	)%
Change in inventories		18.5			65.4			(72	)%
Cash operating costs (a)		173.5			189.7			(9	)%
Add / (subtract)
Depreciation and amortization		48.3			19.5			148	%
Change in inventories		11.9			30.3			(61	)%
Total operating costs (b)		233.7			239.5			(2	)%
Uranium produced & purchased (million lbs) (c)		7.0			8.2			(15	)%
Cash costs per pound (a ÷ c)		24.79			23.14			7	%
Total costs per pound (b ÷ c)		33.38			29.21			14	%

2014 FIRST QUARTER REPORT      17

PRICE SENSITIVITY ANALYSIS: URANIUM

The table and graph below 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, 2014 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, 2014, 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 each quarter. 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
2014		48		48		53		58		64		69		73
2015		41		46		55		65		75		84		92
2016		41		46		57		67		78		87		95
2017		40		46		56		66		76		84		91
2018		40		47		56		66		76		84		90

The table and graph illustrate the mix of long-term contracts in our March 31, 2014 portfolio, and are consistent with our marketing strategy. Both have been updated to reflect deliveries made and contracts entered into up to March 31, 2014.

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:

Sales

• sales volumes on average of 30 million pounds per year, with commitment levels through 2016 higher than in 2017 and 2018

Deliveries

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

• we defer a portion of deliveries under existing contracts for 2014

Annual inflation

• is 1.5% in Canada and 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 17% 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.

18      CAMECO CORPORATION

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

	THREE MONTHS ENDED MARCH 31
HIGHLIGHTS	2014		2013		CHANGE
Production volume (million kgU)		4.0		4.7		(15	)%
Sales volume (million kgU)		1.8		3.4		(47	)%
Average realized price ($Cdn/kgU)		22.41		19.60		14	%
Average unit cost of sales ($Cdn/kgU) (including D&A)		21.36		16.27		31	%
Revenue ($ millions)		40		66		(39	)%
Gross profit ($ millions)		2		11		(82	)%
Gross profit (%)		5		17		(71	)%

FIRST QUARTER

Total revenue decreased by 39% due to a 47% decrease in sales volumes, offset by a 14% increase in realized price.

The total cost of products and services sold (including D&A) decreased by 31% ($38 million compared to $55 million in the first quarter of 2013) due to the decrease in sales volumes, partially offset by an increase in the average unit cost of sales. When compared to 2013, the average unit cost of sales was 31% higher due to the mix of fuel services products sold and lower UF₆ production.

The net effect was a $9 million decrease in gross profit.

NUKEM

	THREE MONTHS ENDED MARCH 31
($ MILLIONS EXCEPT WHERE INDICATED)	2014			2013			CHANGE
Uranium sales (million lbs)		0.7			2.3			(70	)%
Revenue		32			131			(76	)%
Cost of product sold (including D&A)		35			127			(72	)%
Gross profit (loss)		(3	)		4			(175	)%
Net loss		(7	)		(3	)		(133	)%
Adjustments on derivatives1		1			2			(50	)%
Adjusted net loss		(6	)		(1	)		(500	)%

¹  Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (non-IFRS measure, see page 7).

FIRST QUARTER

During the first three months of 2014, NUKEM delivered 0.7 million pounds of uranium, a decline of 1.6 million pounds (70%) due to timing of customer requirements. NUKEM revenues amounted to $32 million as a result of the decline in deliveries and a lower realized price.

Gross loss amounted to $3 million, a decline of $7 million compared to the first quarter of 2013. Included in the gross loss for the quarter is a $6 million write-down of inventory, as a result of a further decline in the spot price that caused the carrying values of certain quantities to exceed their estimated net realizable value.

While sales were significantly lower in the current year, excluding the effects of the inventory write-down, they were at higher margins. On a percentage basis, gross profits were 9% in the first quarter of 2014 compared to 3% in same period last year.

Adjusted net loss for the first three months of 2014 was $6 million, compared to a loss of $1 million in 2013.

2014 FIRST QUARTER REPORT      19

Our operations

Uranium – production overview

Production in our uranium segment this quarter was lower than the first quarter of 2013. See below for more information.

URANIUM PRODUCTION

OUR SHARE	THREE MONTHS ENDED MARCH 31
(MILLION LBS)	2014		2013		CHANGE			2014 PLAN
McArthur River/Key Lake		3.8		3.5		9	%		13.1
Rabbit Lake		0.5		1.1		(55	)%		4.1
Smith Ranch-Highland		0.5		0.3		67	%		2.0
Crow Butte		0.2		0.2		—			0.6
Inkai		0.7		0.8		(13	)%		3.0
Cigar Lake		—		—		—			1.0 - 1.5
Total		5.7		5.9		(3	)%		23.8 - 24.3

Uranium 2014 Q1 updates

Operating properties

McArthur River/Key Lake

Production update

Production for the quarter was 9% higher compared to the same period last year due to efficiency and reliability improvements at the Key Lake mill.

Operations update

We have begun developing the next freeze wall in zone 4. Freezing of zone 4 north is underway, and production from the area is expected to begin this year.

Licensing and production capacity update

At McArthur River, the CNSC has approved an increase of our licence production limit to 21 million pounds (100% basis) per year from the mine. However, the current annual mill production licence limit at Key Lake remains at 18.7 million pounds (100% basis).

As part of our Key Lake extension environmental assessment (EA), we are seeking approval to increase Key Lake’s nominal annual production rate to 25 million pounds and to increase our tailings capacity. A public review and comment period for the EA concluded in February and a regulatory decision is expected this year.

Labour relations

The current collective agreements with unionized employees at McArthur River and Key Lake expired on December 31, 2013. Bargaining began in November, 2013 and is ongoing. There is risk to production if we are unable to reach an agreement and a work stoppage occurs.

Cigar Lake

Production update

In the first quarter, we announced the start of mine production at Cigar Lake. The jet boring system is performing as expected and six ore cavities have been mined to date. The ore is routinely transported to the McClean Lake site where it is being stored for processing.

20      CAMECO CORPORATION

Operations update

AREVA has made good progress on modifications to the McClean Lake mill, and reports the following:

• the ore receiving systems have been commissioned and more than 350 tonnes of ground ore slurry has been shipped from the Cigar Lake mine and loaded into storage tanks at the mill

• an expanded ore slurry storage facility has been completed, including receipt of regulatory approvals

• engineering work related to the mill modifications has been completed, all materials have been ordered and key long-lead items have been received, and a detailed commissioning plan has been prepared

• contractors are on site and the construction is actively progressing

The necessary time to complete all related construction work (installing pumps, pipes, electrical and instrumentation), and commissioning of the new components and the process circuit with water to ensure the systems function as designed, has led AREVA to advise us that the mill will not begin processing ore by the end of the second quarter.

Additionally, AREVA has advised us that work is in progress at McClean Lake to double the mill’s current capacity of 1 million pounds per month in order to process Cigar Lake’s full production, as it is expected to ramp up to 18 million pounds per year by 2018.

We expect to produce 2 million to 3 million packaged pounds (100% basis) in 2014, depending on the mill startup and rampup, as well as the continued success of mining operations at Cigar Lake.

Caution about forward-looking information relating to Cigar Lake

This discussion of our expectations for Cigar Lake, including our plan for 2 million to 3 million packaged pounds (100%) in 2014, 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.

Rabbit Lake

Production update

Production for the quarter was 55% lower compared to the same period last year, mainly due to lower ore grades in the mine and 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, production for the quarter was 40% higher than the first quarter of 2013 due to the addition of the North Butte Satellite operation.

Operations update

We continue to seek and are beginning to receive the necessary approvals to develop our various satellite operations in Wyoming and Nebraska. These projects will remain part of our pipeline and will allow us to retain production flexibility and respond when the market signals new production is needed.

Inkai

Production update

Production was 13% lower compared to the first quarter of 2013. An abnormally heavy snowfall and rapid spring melt made it difficult to deliver reagents and access the operating wellfields.

Operations update

Heavy spring snow melt in the Sozak region of Kazakhstan has resulted in flooding and damage to the access roads that are used to deliver reagents and supplies to several uranium mines. The impact on production at Inkai was minimal, and based on our plans to construct new wellfields, we remain on track for annual production of 3.0 million pounds U₃O₈ (our share).

2014 FIRST QUARTER REPORT      21

Fuel services 2014 Q1 updates

Port Hope conversion services

Cameco Fuel Manufacturing Inc.

Springfields Fuels Ltd. (SFL)

Production update

Fuel services produced 4.0 million kgU in the first quarter, 15% lower than the same period last year. We decreased our production target in 2014 to between 12 million and 13 million kgU, so quarterly production is anticipated to be lower than comparable periods in 2013.

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

• Scott Bishop, manager, technical services, Cameco

Inkai

• Ken Gullen, technical director, international Cameco

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, 2014, 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, 2014, 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, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

22      CAMECO CORPORATION

New standards and interpretations

We were required to apply the following new standards and amendments to existing standards for our accounting periods beginning on or after January 1, 2014. These standards did not have a material impact on the financial statements.

• IAS 32, Financial Instruments: Presentation

• IFRIC 21, Levies

• IAS 36, Impairment of Assets

Refer to our 2013 Annual MD&A for a description of each of the above accounting standards and amendments to existing standards.

The following new standard is not yet effective for the year ended December 31, 2014, and has not been applied in preparing these consolidated financial statements.

IFRS 9, Financial Instruments (IFRS 9)—In October 2010, the International Accounting Standards Board (IASB) issued IFRS 9. In November 2013, the IASB issued a new general hedge accounting standard, which forms part of IFRS 9. The new standard removes the January 1, 2015 effective date of IFRS 9. The new mandatory effective date will be determined once the classification and measurement and impairment phases of IFRS 9 are finalized; however, the IASB has tentatively decided that IFRS 9 would be mandatorily effective for annual periods beginning on or after January 1, 2018.

This standard is part of a wider project to replace IAS 39, Financial Instruments: Recognition and Measurement (IAS 39). 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. While the mandatory effective date has been tentatively set for January 1, 2018, early adoption of the new standard is still 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.

2014 FIRST QUARTER REPORT      23