Cameco (CCJ) 6-K Cameco reports third quarter financial results

Exhibit 99.2

Management’s discussion and analysis

for the quarter ended September 30, 2014

THIRD QUARTER UPDATE	4
CONSOLIDATED FINANCIAL RESULTS	8
OUTLOOK FOR 2014	15
LIQUIDITY AND CAPITAL RESOURCES	17
FINANCIAL RESULTS BY SEGMENT
URANIUM	19
FUEL SERVICES	21
NUKEM	22
OUR OPERATIONS	22
URANIUM Q3 UPDATES	23
FUEL SERVICES Q3 UPDATES	24
QUALIFIED PERSONS	24
ADDITIONAL INFORMATION	25

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 September 30, 2014 (interim financial statements). The information is based on what we knew as of October 28, 2014 and updates our first quarter, second quarter and 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 termswe, us, ourandCamecomean 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 beforward-looking information orforward-looking statements under Canadian and United States securities laws. We refer to them in this MD&A asforward-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, first and second quarter MD&A, which include 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 headingOur strategy

• our expectations about 2014 and future global uranium supply and demand including the discussion under the headingUranium market update

• our expectations for uranium deliveries in the fourth quarter 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 price sensitivity analysis for our uranium segment

• 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 we will continue to invest in maintaining and expanding our production capacity over the next several years

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

• our plan for between 0.2 million and 0.6 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 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, 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 16,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 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 the additional jet boring equipment is acquired on schedule, the jet boring mining method works as anticipated and the deposit freezes as planned

• the McClean Lake mill is able to process Cigar Lake ore as expected, including our expectation of processing between 0.2 million and 0.6 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, 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 THIRD 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 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.

Third 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 ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED SEPTEMBER 30					CHANGE			NINE MONTHS ENDED SEPTEMBER 30				CHANGE
	2014			2013					2014		2013
Revenue		587			597		(2	)%		1,508		1,461		3	%
Gross profit		143			228		(37	)%		386		422		(9	)%
Net earnings (losses) attributable to equity holders		(146	)		211		(170	)%		113		254		(56	)%
$ per common share (diluted)		(0.37	)		0.53		(170	)%		0.28		0.64		(56	)%
Adjusted net earnings (non-IFRS, see page 9)		93			208		(55	)%		207		295		(30	)%
$ per common share (adjusted and diluted)		0.23			0.53		(57	)%		0.52		0.75		(31	)%
Cash provided by (used in) continuing operations (after working capital changes)		263			154		71	%		244		361		(32	)%

THIRD QUARTER

Net losses attributable to equity holders (net losses) this quarter were $146 million ($0.37 per share diluted) compared to net earnings attributable to equity holders (net earnings) of $211 million ($0.53 per share diluted) in the third quarter of 2013. In addition to the items noted below, our net losses were affected by the impairment of our investment in GE-Hitachi Global Laser Enrichment (GLE) of $184 million, the impairment of our investment in GoviEx Uranium Inc. (GoviEx) of $12 million, and mark-to-market losses on foreign exchange derivatives compared to gains in 2013.

4    CAMECO CORPORATION

On an adjusted basis, our net earnings this quarter were $93 million ($0.23 per share diluted) compared to $208 million ($0.53 per share diluted) (non-IFRS measure, see page 9) in the third quarter of 2013. The change was mainly due to:

• lower earnings from our uranium segment based on a higher cost of sales and lower Canadian and US dollar average realized prices

• no earnings from BPLP due to the divestiture of our interest in the first quarter of this year

partially offset by:

• tax recoveries due to pre-tax losses in Canada

SeeFinancial results by segment on page 19 for more detailed discussion.

FIRST NINE MONTHS

Net earnings in the first nine months of the year were $113 million ($0.28 per share diluted) compared to $254 million ($0.64 per share diluted) in the first nine months of 2013. In addition to the items noted below, net earnings were impacted by a gain on the sale of our interest in BPLP of $127 million, the impairment of our investment in GLE of $184 million, the impairment of our investment in GoviEx of $12 million, and higher mark-to-market losses on foreign exchange derivatives compared to 2013.

On an adjusted basis, our net earnings for the first nine months of this year were $207 million ($0.52 per share diluted) compared to $295 million ($0.75 per share diluted) (non-IFRS measure, see page 9) for the first nine months of 2013, mainly due to:

• lower earnings from our uranium business based on a higher cost of sales

• 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

• settlement costs of $12 million with respect to the early redemption our Series C debentures

• no earnings from BPLP due to the divestiture of our interest in the first quarter of this year

partially offset by:

• a favourable settlement of $28 million with respect to a dispute regarding a long-term supply contract with a utility customer

• lower expenditures on exploration due to decreased activity in Australia and a more focused effort on our core projects in Saskatchewan

• higher tax recoveries due to pre-tax losses in Canada

SeeFinancial results by segment on page 19 for more detailed discussion.

Operations update

(includes sales of 1 million pounds between our uranium, fuel services and NUKEM segments)

HIGHLIGHTS		THREE MONTHS ENDED SEPTEMBER 30					CHANGE			NINE MONTHS ENDED SEPTEMBER 30				CHANGE
		2014		2013						2014		2013
Uranium	Production volume (million lbs)		5.4		5.8			(7	)%		15.1		16.2		(7	)%
	Sales volume (million lbs)		9.0		8.5			6	%		23.3		20.1		16	%
	Average realized price ($US/lb)		45.87		50.73			(10	)%		46.14		48.72		(5	)%
	($Cdn/lb)		49.83		52.59			(5	)%		50.35		49.81		1	%
	Revenue ($ millions)		447		449			—			1,171		1,001		17	%
	Gross profit ($ millions)		132		226			(42	)%		362		400		(10	)%
Fuel services	Production volume (million kgU)		1.1		2.6			(58	)%		8.9		12.2		(27	)%
	Sales volume (million kgU)		3.1		3.8			(18	)%		8.2		11.1		(26	)%
	Average realized price ($Cdn/kgU)		23.11		20.03			15	%		22.21		18.63		19	%
	Revenue ($ millions)		71		77			(8	)%		182		208		(13	)%
	Gross profit ($ millions)		5		13			(62	)%		23		34		(32	)%
NUKEM	Sales volume U3O8(million lbs)		2.5		2.1			19	%		4.7		5.6		(16	)%
	Average realized price ($Cdn/lb)		38.52		40.24			(4	)%		39.72		42.50		(7	)%
	Revenue ($ millions)		97		93			4	%		190		276		(31	)%
	Gross profit ($ millions)		9		(7	)		229	%		19		1		1800	%

2014 THIRD QUARTER REPORT    5

Production in our uranium segment this quarter was 7% lower compared to the third quarter of 2013 due to a labour disruption at McArthur River/Key Lake in the third quarter of 2014 that resulted in an unplanned shutdown. SeeUranium Q3 updates starting on page 23 for more information.

Key highlights:

• on October 6, unionized employees at McArthur River and Key Lake accepted a new four-year contract that includes a 12% wage increase over the term of the agreement. The previous contract expired on December 31, 2013.

• on October 8, we announced that the McClean Lake mill had started producing uranium concentrate from ore mined at the Cigar Lake operation in northern Saskatchewan

Production in our fuel services segment was 58% lower this quarter than in the third quarter of 2013 primarily due to an extended planned shutdown and lower demand, as well as a lower than expected final delivery from SFL under the toll conversion contract.

Also of note this quarter:

In July 2014, the majority partner of GLE decided to significantly reduce funding to GLE. In accordance with the provisions of IAS 36Impairment of Assets, we considered this to be an indicator that our investment in GLE could potentially be impaired and, accordingly, we estimated the assets’ recoverable amount. As a result of this review, we have impaired the full value of our investment and recorded a charge of $184 million in the third quarter.

Also in the third quarter, we recorded an impairment on our investment in GoviEx. GoviEx recently became listed on the Canadian Securities Exchange. With the availability of a quoted market price, we determined that there was a significant decline in the fair value of our investment in GoviEx and as a result, we recorded an impairment of $12 million.

Uranium market update

The market in the third quarter of 2014 showed no fundamental change from the first half of the year. It remains in a state of surplus supply as a result of factors like the lack of reactor restarts in Japan. That said, we did see a 25% increase in the spot price during the quarter, as prices moved from the high-$20s to mid-$30s (US). We believe this increase can be attributed to market speculation surrounding the uncertain impact of potential Russian sanctions, the possible interruption of US Department of Energy inventory dispositions, the reduction in supply from our own McArthur River/Key Lake operation as a result of a labour disruption, and normal course activity from traders and financial players. There have also been some indications that investors may be looking to step in to take positions in physical uranium, but it is too early to speculate on the potential impact of this activity on the market.

Whether the spot price increase is sustainable is yet to be seen. Utilities remain well covered, and while Japan is edging ever closer to restarting some reactors, it’s clear that the restart approval process will continue to be challenging. Meanwhile, supply is readily available for the near term, though it has diminished over the long term as a result of project delays and cancellations. So while, overall, there have been some positive developments, nothing fundamental has changed in the uranium market for the near term.

The long-term outlook remains positive, as nuclear growth continues around the world. Approximately 70 new reactors are under construction and even more are planned. This reactor growth, combined with the timing, development and execution of new supply projects, along with 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 and demand, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the headingCaution about forward-looking information beginning on page 2.

6    CAMECO CORPORATION

Industry Prices

	SEP 30 2014		JUN 30 2014		MAR 31 2014		SEPT 30 2013		JUN 30 2013		MAR 31 2013
Uranium ($US/lb U3O8) 1
Average spot market price		35.40		28.23		34.00		35.00		39.60		42.25
Average long-term price		45.00		44.50		46.00		50.50		57.00		56.50
Fuel services ($US/kgU as UF6)1
Average spot market price
North America		7.25		7.25		7.63		9.00		10.00		10.50
Europe		7.50		7.50		8.00		9.50		10.38		11.00
Average long-term price
North America		16.00		16.00		16.00		16.38		16.75		16.75
Europe		17.00		17.00		17.00		17.13		17.25		17.25

Note: the industry does not publish UO₂prices.

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 third quarter of 2014 was approximately 12 million pounds, which is the same volume reported for the third quarter of 2013.

At the end of the quarter, the average reported spot price increased 25% to $35.40 (US) per pound, and the average reported long-term price increased to $45.00 (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 and long-term UF₆ conversion prices held firm during the quarter.

SHARES AND STOCK OPTIONS OUTSTANDING   At October 27, 2014, we had:   •   395,791,522 common shares and one Class B share outstanding   •   8,384,212 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.  

2014 THIRD 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 ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED SEPTEMBER 30					CHANGE			NINE MONTHS ENDED SEPTEMBER 30				CHANGE
	2014			2013					2014		2013
Revenue		587			597		(2	)%		1,508		1,461		3	%
Gross profit		143			228		(37	)%		386		422		(9	)%
Net earnings (losses) attributable to equity holders		(146	)		211		(170	)%		113		254		(56	)%
$ per common share (basic)		(0.37	)		0.53		(170	)%		0.28		0.64		(56	)%
$ per common share (diluted)		(0.37	)		0.53		(170	)%		0.28		0.64		(56	)%
Adjusted net earnings (non-IFRS, see page 9)		93			208		(55	)%		207		295		(30	)%
$ per common share (adjusted and diluted)		0.23		��	0.53		(57	)%		0.52		0.75		(31	)%
Cash provided by (used in) continuing operations (after working capital changes)		263			154		71	%		244		361		(32	)%

Net earnings

Net losses this quarter were $146 million ($0.37 per share diluted) compared to net earnings of $211 million ($0.53 per share diluted) in the third quarter of 2013. In addition to the items noted below, our net losses were affected by the impairment of our investment in GLE of $184 million, the impairment of our investment in GoviEx of $12 million, and mark-to-market losses on foreign exchange derivatives compared to gains in 2013.

On an adjusted basis, our net earnings this quarter were $93 million ($0.23 per share diluted) compared to $208 million ($0.53 per share diluted) (non-IFRS measure, see page 9) in the third quarter of 2013. The change was mainly due to:

• lower earnings from our uranium segment based on a higher cost of sales and lower Canadian and US dollar average realized prices

• no earnings from BPLP due to the divestiture of our interest in the first quarter of this year

partially offset by:

• tax recoveries due to pre-tax losses in Canada

Net earnings in the first nine months of the year were $113 million ($0.28 per share diluted) compared to $254 million ($0.64 per share diluted) in the first nine months of 2013. In addition to the items noted below, net earnings were impacted by a gain on the sale of our interest in BPLP of $127 million, the impairment of our investment in GLE of $184 million, the impairment of our investment in GoviEx of $12 million, and higher mark-to-market losses on foreign exchange derivatives compared to 2013.

On an adjusted basis, our net earnings for the first nine months of this year were $207 million ($0.52 per share diluted) compared to $295 million ($0.75 per share diluted) (non-IFRS measure, see page 9) for the first nine months of 2013, mainly due to:

• lower earnings from our uranium business based on a higher cost of sales

• 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

• settlement costs of $12 million with respect to the early redemption our Series C debentures

• no earnings from BPLP due to the divestiture of our interest in the first quarter of this year

partially offset by:

• a favourable settlement of $28 million with respect to a dispute regarding a long-term supply contract with a utility customer

8    CAMECO CORPORATION

• lower expenditures on exploration due to decreased activity in Australia and a more focused effort on our core projects in Saskatchewan

• higher tax recoveries due to pre-tax losses in Canada

SeeFinancial results by segment on page 19 for more detailed discussion.

Adjusted net earnings (non-IFRS measure)

Adjusted net earnings is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS measure). We use this measure as a 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 (losses) 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 (pre-tax), impairment charges, 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 below reconciles adjusted net earnings with our net earnings.

($ MILLIONS)	THREE MONTHS ENDED SEPTEMBER 30						NINE MONTHS ENDED SEPTEMBER 30
	2014			2013			2014			2013
Net earnings (loss) attributable to equity holders		(146	)		211			113			254
Adjustments
Adjustments on derivatives1(pre-tax)		60			(41	)		37			20
NUKEM purchase price inventory write-down (pre-tax)		(2	)		17			(2	)		17
Impairment charges		196			15			196			15
Gain on interest in BPLP (after tax)		—			—			(127	)		—
Income taxes on adjustments		(15	)		6			(10	)		(11	)
Adjusted net earnings		93			208			207			295

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.

2014 THIRD QUARTER REPORT    9

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

($ MILLIONS)		THREE MONTHS ENDED SEPTEMBER 30			NINE MONTHS ENDED SEPTEMBER 30
Adjusted net earnings – 2013			208			295
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 Lower realized prices ($US) Foreign exchange impact on realized prices Higher costs Hedging benefits		11 (43 19 (80 (13	)  )  )		63 (60 72 (114 (32	)  )  )
	change –uranium		(106	)		(71	)
Fuel services	Lower sales volume Higher realized prices ($Cdn) Higher costs Hedging benefits		(3 9 (14 (1	)  )  )		(9 29 (31 (2	)  )  )
	change –fuel services		(9	)		(13	)
NUKEM	Gross profit		(2	)		—
	change –NUKEM		(2	)		—
Other changes
(Higher)/lower administration expenditures			(5	)		12
Lower exploration expenditures			9			22
Loss on disposal of assets			(2	)		(7	)
Debenture redemption premium			—			(12	)
Foreign exchange			18			3
Earnings from BPLP			(63	)		(65	)
Loss on equity accounted investments			(1	)		(12	)
Contract termination fee (SFL)			—			(18	)
Partial arbitration award			—			28
Lower income taxes			51			51
Other			(5	)		(6	)
Adjusted net earnings – 2014			93			207

SeeFinancial results by segment on page 19 for more detailed discussion.

Quarterly trends

HIGHLIGHTS ($ MILLIONS EXCEPT PER SHARE AMOUNTS)	2014								2013									2012
	Q3			Q2			Q1		Q4		Q3		Q2			Q1		Q41
Revenue		587			502			419		977		597		421			444		846
Net earnings (losses) attributable to equity holders		(146	)		127			131		64		211		34			9		41
$ per common share (basic)		(0.37	)		0.32			0.33		0.16		0.53		0.09			0.02		0.10
$ per common share (diluted)		(0.37	)		0.32			0.33		0.16		0.53		0.09			0.02		0.10
Adjusted net earnings (non-IFRS, see page 9)		93			79			36		150		208		61			27		233
$ per common share (adjusted and diluted)		0.23			0.20			0.09		0.38		0.53		0.15			0.07		0.59
Earnings (losses) from continuing operations		(146	)		127			4		29		163		33			8		7
$ per common share (basic)		(0.37	)		0.32			0.01		0.07		0.41		0.08			0.02		0.02
$ per common share (diluted)		(0.37	)		0.32			0.01		0.07		0.41		0.08			0.02		0.02
Cash provided by (used in) continuing operations (after working capital changes)		263			(25	)		7		163		154		(33	)		241		281

¹  Our quarterly results have been revised in accordance withIFRS 11 – Joint Arrangements andIAS 19 – Employee Benefits.

Key things to note:

• our financial results are strongly influenced by the performance of our uranium segment, which accounted for 76% of consolidated revenues in the third quarter of 2014

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

10    CAMECO CORPORATION

• 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 9 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)	2014									2013												2012
	Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q42
Net earnings attributable to equity holders		(146	)		127			131			64			211			34			9			41
Adjustments
Adjustments on derivatives1 (pre-tax)		60			(66	)		44			36			(41	)		36			25			33
NUKEM purchase price inventory write-down (pre-tax)		(2	)		—			—			(3	)		17			—			—			—
Impairment charges		196			—			—			70			15			—			—			168
Income taxes on adjustments		(15	)		18			(12	)		(17	)		6			(9	)		(7	)		(9	)
Gain on sale of BPLP (after tax)		—			—			(127	)		—			—			—			—			—
Adjusted net earnings (non-IFRS, see page 9)		93			79			36			150			208			61			27			233

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.

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 SEPTEMBER 30					NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)	2014		2013			2014			2013
Share of earnings from BPLP and related entities				63						65
Tax expense		—		(15	)		—			(16	)
				48			—			49
Gain on disposal of BPLP and related entities		—		—			145			—
Tax expense on disposal				—			(18	)		—
		—		—			127			—
Net earnings from discontinued operations		—		48			127			49

Corporate expenses

ADMINISTRATION

($ MILLIONS)	THREE MONTHS ENDED SEPTEMBER 30				CHANGE			NINE MONTHS ENDED SEPTEMBER 30				CHANGE
	2014		2013					2014		2013
Direct administration		38		34		12	%		112		114		(2	)%
Restructuring charges		—		—		—			—		5		(100	)%
Stock-based compensation		2		2		—			10		15		(33	)%
Total administration		40		36		11	%		122		134		(9	)%

2014 THIRD QUARTER REPORT    11

Direct administration costs were $4 million higher for the third quarter compared to the same period last year due to the timing of expenditures. For the first nine months, direct administration costs were $2 million lower due to the NUKEM advisory fee paid in 2013 ($3 million).

Stock based compensation in the first nine months was $5 million lower than in 2013 due to a change in the compensation program.

EXPLORATION

In the third quarter, uranium exploration expenses were $11 million, a decrease of $9 million compared to the third quarter of 2013. Exploration expenses for the first nine months of the year decreased to $35 million from $56 million in 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 $48 million in the third quarter of 2014 compared to an expense of $9 million in the third quarter of 2013. The change in the net recovery was due to losses incurred in the third quarter of 2014 combined with a change in the distribution of earnings between jurisdictions. In 2014, we recorded losses of $241 million in Canada compared to $40 million in 2013 while earnings in foreign jurisdictions decreased to $47 million from earnings of $212 million, due to the impairment of our investment in GLE of $184 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 $32 million this quarter compared to an expense of $19 million in the third quarter of 2013 due to higher pre-tax adjusted earnings in 2013, and a change in the distribution of earnings between jurisdictions.

In the first nine months of 2014, we recorded an income tax recovery of $99 million compared to a recovery of $65 million in 2013. The change in the net recovery was due to losses incurred in the first nine months of 2014 combined with a change in the distribution of earnings between jurisdictions. In 2014, we recorded losses of $483 million in Canada compared to $368 million in 2013, while earnings in foreign jurisdictions decreased to $368 million from $508 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 $90 million for the first nine months compared to a recovery of $38 million in 2013.

	THREE MONTHS ENDED SEPTEMBER 30						NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)	2014			2013			2014			2013
Pre-tax adjusted earnings1
Canada2		(169	)		(12	)		(435	)		(274	)
Foreign		229			238			552			530
Total pre-tax adjusted earnings		60			226			117			256
Adjusted income taxes1
Canada2		(43	)		(1	)		(111	)		(64	)
Foreign		11			20			21			26
Adjusted income tax expense (recovery)		(32	)		19			(90	)		(38	)
Effective tax rate		(53	)%		8	%		(77	)%		(15	)%

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 9).

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 2009 tax returns. We continue

12    CAMECO CORPORATION

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.

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) 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

The majority of our customers are located outside Canada and we established a marketing structure involving foreign companies including Cameco Europe Ltd., which entered into intercompany purchase and sale agreements with Cameco as well as uranium supply agreements with third parties. Cameco and Cameco Europe Ltd. made reasonable efforts to put arm’s length transfer pricing arrangements in place, and these arrangements expose both parties to the risks and rewards accruing to them under this portfolio of purchase and sales contracts.

The intercompany contract prices 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 $79 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 September 30, 2014.

We are confident that we will be successful in our case; however, 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. 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 $219 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		110		50		—		160
Total		111		72		36		219

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 $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. While in dispute, 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. The estimated amounts summarized in the table below reflect actual amounts paid and estimated future payments to CRA.

$ MILLIONS	2003 - 2013		20142		2015 - 2016		2017 - 2023		TOTAL
50% of cash taxes and transfer pricing penalties payable in the period1		37		115 - 175		410 - 435		0 - 25		625 - 650

¹ These amounts do not include interest and instalment penalties, which totaled approximately $72 million to September 30, 2014.

²  These amounts include $110 million already paid in 2014.

2014 THIRD QUARTER REPORT    13

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 $219 million already paid to date.

Our appeal of the 2003 reassessment is expected to be heard in the Tax Court of Canada in 2015. If this timing is adhered to, we expect to have a Tax Court decision during 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 is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the headingCaution 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 2013 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 (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 $79 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 2010 through 2013 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 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

FOREIGN EXCHANGE

At September 30, 2014:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.12 (Cdn), up from $1.00 (US) for $1.07 (Cdn) at June 30, 2014. The exchange rate averaged $1.00 (US) for $1.09 (Cdn) over the quarter.

• We had foreign currency contracts of $1.8 billion (US) at September 30, 2014. The mark-to-market loss on all foreign exchange contracts was $36 million compared to a $23 million gain at June 30, 2014. The average exchange rate for USD currency contracts was $1.00 (US) for $1.11 (Cdn).

14    CAMECO CORPORATION

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 production, uranium average unit cost of sales, fuel services production, fuel services sales volume, fuel services revenue, NUKEM sales volume, NUKEM revenue, consolidated revenue, consolidated 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.

SeeFinancial results by segment on page 19 for details.

2014 FINANCIAL OUTLOOK

	CONSOLIDATED	URANIUM	FUEL SERVICES	NUKEM
Production	—	22.6 to 22.8 million lbs	11 to 12 million kgU	—
Sales volume	—	31 to 33 million lbs1	Decrease 10% to 15%	7 to 8 million lbs U3O8
Revenue compared to 2013	Decrease 0% to 5%	Increase 5% to 10%2	Decrease 0% to 5%	Decrease 25% to 30%
Average unit cost of sales (including D&A)	—	Increase 5% to 10%3	Increase 0% to 5%	Decrease 15% to 20%
Direct administration costs compared to 20134	Increase 0% to 5%	—	—	Increase 0% to 5%
Exploration costs compared to 2013	—	Decrease 25% to 30%	—	—
Tax rate	Recovery of 40% to 45%	—	—	Expense of 30% to 35%
Capital expenditures	$490 million	—	—	—

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

²  Based on a uranium spot price of $36.50 (US) per pound (the Ux spot price as of October 27, 2014), a long-term price indicator of $45.00 (US) per pound (the Ux long-term indicator on October 27, 2014) and an exchange rate of $1.00 (US) for $1.09 (Cdn).

³  This increase is based on the unit cost of sale for produced material and committed long-term purchases, and spot purchases made to September 30, 2014. If we make additional discretionary purchases during the remainder of 2014, then we expect the overall unit cost of sales could be different.

⁴  Direct administration costs do not include stock-based compensation expenses. See page 11 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 are on track to meet our 2014 uranium sales targets, and, therefore, expect to deliver 8 million to 10 million pounds in the fourth quarter.

We have decreased our uranium production outlook to be between 22.6 million and 22.8 million pounds U₃O₈ (previously between 22.8 million and 23.3 million pounds) to reflect the impact of the labour disruption at McArthur River/Key Lake, as well as our expected production from Cigar Lake/McClean Lake. SeeUranium Q3 updates starting on page 23 for more information.

Average unit cost of sales in our uranium segment are now expected to increase 5% to 10% (previously an increase of up to 5%). Cost of sales has increased due to higher unit production costs in light of lower overall production, and the continued payment of stand-by costs for the McClean Lake mill, which are charged to cost of sales.

In our fuel services segment, we have lowered our outlook for annual production to between 11 million and 12 million kgU (previously 12 million to 13 million kgU) due to a lower than expected final delivery from SFL under the toll conversion contract.

We now expect fuel services revenue to decrease by up to 5% (previously a 5% to 10% decrease) due to higher expected average realized prices. The increase in average realized prices is slightly offset by a lower outlook for expected sales volumes, which we now expect to decrease by 10% to 15% (previously a decrease of 5% to 10%) due to market conditions.

2014 THIRD QUARTER REPORT    15

We now expect consolidated revenue to decrease by up to 5% (previously an increase of 5% to 10%), primarily as a result of the decrease in our sales and revenue outlook for NUKEM in the third quarter. We expect NUKEM to sell between 7 million and 8 million pounds (previously expected sales of 7 million to 9 million pounds). As a result, we now expect NUKEM’s revenue to decrease by 25% to 30% (previously a decrease of 15% to 20%) due to the ongoing weakness in the uranium market.

We now expect a recovery of 40% to 45% for our consolidated tax rate (previously a 30% to 35% recovery) due to a change in the distribution of earnings between jurisdictions.

Capital expenditures are now expected to be $490 million (previously $550 million) due to timing of project work, resulting in the deferral of some costs to 2015.

SENSITIVITY ANALYSIS

For the rest of 2014:

• a change of $5 (US) per pound in both the Ux spot price ($36.50 (US) per pound on October 27, 2014) and the Ux long-term price indicator ($45.00 (US) per pound on October 27, 2014) would change revenue by $20 million and net earnings by $8 million

• a one-cent change in the value of the Canadian dollar versus the US dollar would effectively change revenue by $3 million and adjusted net earnings by less than $1 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).

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

The table below and graph on the following page 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 September 30, 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 September 30, 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. 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		47		48		49		51		53		55		57
2015		41		46		55		65		74		83		91
2016		42		47		57		68		78		88		96
2017		41		47		57		67		78		87		94
2018		42		48		58		68		78		87		94

16    CAMECO CORPORATION

The table and graph illustrate the mix of long-term contracts in our September 30, 2014 portfolio, and are consistent with our marketing strategy. Both have been updated to reflect deliveries made and contracts entered into up to September 30, 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

• 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 2014

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 18% 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 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 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 penalties. We have provided an estimate of the amount and timing of the expected cash taxes and transfer pricing penalties payable in the table on page 13.

CASH FROM CONTINUING OPERATIONS

Cash from continuing operations was $109 million higher this quarter than in 2013, largely due to a decrease in working capital requirements, partially offset by an increase in income taxes paid. Working capital required $181 million less than in 2013 largely as a result of an increase in accounts payable during the period. Not including working capital requirements, our operating cash flows this quarter were lower by $72 million.

Cash from continuing operations was $117 million lower in the first nine months of 2014 than for the same period in 2013, largely due to an increase in income taxes paid, partially offset by a decrease in working capital requirements. Working capital required $63 million less in 2014. Not including working capital requirements, our operating cash flows in the first nine months were lower by $180 million.

DEBT

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $2.3 billion at September 30, 2014, unchanged from June 30, 2014. At September 30, 2014, we had approximately $925 million outstanding in letters of credit.

2014 THIRD 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 September 30, 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 September 30, 2014:

• purchase commitments

• financial assurances

There have been no material changes to our long-term contractual obligations since December 31, 2013. Our long-term contractual obligations do not include our sales and purchase commitments. Please see our annual MD&A for more information.

PURCHASE COMMITMENTS

SEPTEMBER 30 ($ MILLIONS)	2014		2015 AND 2016		2017 AND 2018		2019 AND BEYOND		TOTAL
Purchase commitments1		171		793		221		436		1,621

¹  Denominated in US dollars, converted to Canadian dollars as of September 30, 2014 at the rate of $1.12.

During the third 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.

As of September 30, 2014, we had commitments of about $1.6 billion (Cdn) for the following:

• approximately 31 million pounds of U₃O₈ equivalent from 2014 to 2028

• approximately 3 million kgU as UF₆ in conversion services from 2014 to 2018

• 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 its agreements other than pursuant to customary event of default provisions.

FINANCIAL ASSURANCES

At September 30, 2014, our financial assurances totaled $925 million compared to $910 million at June 30, 2014. The increase is mainly due to exchange rate fluctuations.

BALANCE SHEET

($ MILLIONS)	SEPTEMBER 30, 2014		DECEMBER 31, 2013		CHANGE
Cash, short-term investments and bank overdraft		508		188		170	%
Total debt		1,491		1,344		11	%
Inventory		957		913		5	%

Total cash and short-term investments at September 30, 2014 were $508 million, or 170% higher than at December 31, 2013 due to completion of the sale of BPLP in March, and the issuance of the Series G debentures in June. Net debt at September 30, 2014 was $983 million.

Total debt increased by $147 million to $1,491 million at September 30, 2014, due to the early redemption of our Series C debentures and the issuance of the Series G debentures. See note 9 of our interim financial statements for more detail.

Total product inventories increased to $957 million, including NUKEM’s inventories ($329 million). The increase was largely due to an increase in NUKEM’s inventory and was partially offset by a decrease in inventories in our uranium segment. Inventories in our uranium segment decreased as sales were higher than production and purchases in the first nine months of the year.

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

18    CAMECO CORPORATION

Financial results by segment

Uranium

(includes sales of 1 million pounds between our uranium, fuel services and NUKEM segments)

HIGHLIGHTS	THREE MONTHS ENDED SEPTEMBER 30				CHANGE			NINE MONTHS ENDED SEPTEMBER 30				CHANGE
	2014		2013					2014		2013
Production volume (million lbs)		5.4		5.8		(7	)%		15.1		16.2		(7	)%
Sales volume (million lbs)		9.0		8.5		6	%		23.3		20.1		16	%
Average spot price ($US/lb)		31.80		34.75		(8	)%		31.90		39.21		(19	)%
Average long-term price ($US/lb)		44.33		53.00		(16	)%		45.94		55.50		(17	)%
Average realized price
($US/lb)		45.87		50.73		(10	)%		46.14		48.72		(5	)%
($Cdn/lb)		49.83		52.59		(5	)%		50.35		49.81		1	%
Average unit cost of sales ($Cdn/lb) (including D&A)		35.09		26.19		34	%		34.81		29.91		16	%
Revenue ($ millions)		447		449		—			1,171		1,001		17	%
Gross profit ($ millions)		132		226		(42	)%		362		400		(10	)%
Gross profit (%)		30		50		(40	)%		31		40		(23	)%

THIRD QUARTER

Production volumes this quarter were 7% lower compared to the third quarter of 2013 due to a labour disruption at McArthur River/Key Lake that resulted in an unplanned shutdown. SeeUranium Q3 updates starting on page 23 for more information.

Uranium revenues for the quarter remained flat compared to the third quarter of 2013 as a 6% increase in sales volumes was offset by a 5% decrease in the Canadian dollar average realized price.

Our realized prices this quarter were lower than the third quarter of 2013, primarily as a result of a decrease in the price realized on deliveries under market-related contracts, offset by the weakening of the Canadian dollar compared to 2013. In the third 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 $1.04 (Cdn) in the third quarter of 2013.

Total cost of sales (including D&A) increased by 41% ($315 million compared to $224 million in 2013). This was mainly the result of a 6% increase in sales volumes and an increase in the average non-cash unit cost of inventory.

The net effect was a $94 million decrease 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.

FIRST NINE MONTHS

Production volumes for the first nine months of the year were 7% lower than in the previous year due to lower production from McArthur/Key Lake, Crow Butte and Inkai. SeeUranium Q3 updates starting on page 23 for more information.

For the first nine months of 2014, uranium revenues increased 17% compared to 2013, due to a 16% increase in sales volumes, and a 1% increase in the Canadian dollar average realized price. Sales in the first nine months were higher than in 2013 due to a change in the timing of deliveries, which can vary significantly and are driven by customer requests.

Our realized prices for the first nine months of 2014 were higher than 2013 primarily as a result of the weakening of the Canadian dollar compared to 2013, partially offset by a decrease in the price realized on deliveries under market related contracts. For the first nine months of 2014, the exchange rate on the average

2014 THIRD QUARTER REPORT    19

realized price was $1.00 (US) for $1.09 (Cdn), compared to $1.00 (US) for $1.02 (Cdn) for the same period in 2013.

Total cost of sales (including D&A) increased by 35% ($810 million compared to $601 million in 2013) mainly due to a 16% increase in sales volumes, an increase in non-cash costs, and an increase in cash costs which was primarily the result of an increased cost of purchases. For the first nine months of 2014, total non-cash costs were $176 million compared to $92 million for the same period in 2013 due to an increase in the average non-cash unit cost of inventory, and the completion of several capital projects at our production facilities. As discussed in our annual MD&A, upon project completion, we begin to depreciate the asset, which increases the non-cash portion of our production costs.

The net effect was a $38 million decrease in gross profit for the first nine months.

Previously, our most significant long-term purchase contract was the Russian Highly Enriched Uranium (HEU) commercial agreement, which ended in 2013. With that source of supply no longer available, and until Cigar Lake ramps up to full production, to meet our delivery commitments, we will make use of our inventories and we may purchase material where it is beneficial to do so. We expect our purchases will result in profitable sales; however, the cost of purchased material may be higher or lower than our other sources of supply, depending on market conditions.

The table below shows the costs of produced and purchased uranium incurred in the reporting periods (which are non-IFRS measures, see the paragraphs below the table). These costs do not include selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.

($CDN/LB)	THREE MONTHS ENDED SEPTEMBER 30				CHANGE			NINE MONTHS ENDED SEPTEMBER 30				CHANGE
	2014		2013					2014		2013
Produced
Cash cost		17.91		17.68		1	%		21.19		19.66		8	%
Non-cash cost		7.31		10.63		(31	)%		10.47		9.48		10	%
Total production cost		25.22		28.31		(11	)%		31.66		29.14		9	%
Quantity produced (million lbs)		5.4		5.8		(7	)%		15.1		16.2		(7	)%
Purchased
Cash cost		30.91		16.57		87	%		37.25		23.25		60	%
Quantity purchased (million lbs)		1.8		3.8		(53	)%		3.4		8.7		(61	)%
Totals
Produced and purchased costs		26.64		23.66		13	%		32.69		27.08		21	%
Quantities produced and purchased (million lbs)		7.2		9.6		(25	)%		18.5		24.9		(26	)%

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 table on the following page presents a reconciliation of these measures to our unit cost of sales for the third quarters and the first nine months of 2014 and 2013.

20    CAMECO CORPORATION

CASH AND TOTAL COST PER POUND RECONCILIATION

	THREE MONTHS ENDED SEPTEMBER 30						NINE MONTHS ENDED SEPTEMBER 30
($ MILLIONS)	2014			2013			2014			2013
Cost of product sold		248.2			198.2			633.8			509.4
Add / (subtract)
Royalties		(21.5	)		(6.2	)		(56.7	)		(38.3	)
Standby charges		(5.8	)		(9.1	)		(24.8	)		(26.3	)
Other selling costs		(1.2	)		(0.1	)		(6.7	)		3.4
Change in inventories		(67.3	)		(17.3	)		(99.0	)		72.5
Cash operating costs (a)		152.4			165.5			446.6			520.7
Add / (subtract)
Depreciation and amortization		66.7			25.6			175.9			91.7
Change in inventories		(27.3	)		36.0			(17.7	)		61.9
Total operating costs (b)		191.8			227.1			604.8			674.3
Uranium produced & purchased (millions lbs)(c)		7.2			9.6			18.5			24.9
Cash costs per pound (a ÷ c)		21.16			17.24			24.14			20.91
Total costs per pound (b ÷ c)		26.64			23.66			32.69			27.08

Fuel services

(includes results for UF₆, UO₂and fuel fabrication)

	THREE MONTHS ENDED SEPTEMBER 30				CHANGE			NINE MONTHS ENDED SEPTEMBER 30				CHANGE
HIGHLIGHTS	2014		2013					2014		2013
Production volume (million kgU)		1.1		2.6		(58	)%		8.9		12.2		(27	)%
Sales volume (million kgU)		3.1		3.8		(18	)%		8.2		11.1		(26	)%
Average realized price ($Cdn/kgU)		23.11		20.03		15	%		22.21		18.63		19	%
Average unit cost of sales ($Cdn/kgU) (including D&A)		21.55		16.63		30	%		19.46		15.58		25	%
Revenue ($ millions)		71		77		(8	)%		182		208		(13	)%
Gross profit ($ millions)		5		13		(62	)%		23		34		(32	)%
Gross profit (%)		7		17		(59	)%		13		16		(19	)%

THIRD QUARTER

Total revenue decreased by 8% due to an 18% decrease in sales volume, partially offset by a 15% increase in average realized price. Realized prices were higher, primarily due to the mix of fuel services products sold compared to 2013.

The total cost of products and services sold (including D&A) increased by 3% ($66 million compared to $64 million in the third quarter of 2013) due to an increase in the average unit cost of sales, offset by a decrease in sales volumes. When compared to 2013, the average unit cost of sales was 30% higher due to higher unit production costs as a result of lower production for UF₆ and the mix of fuel services products sold.

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

FIRST NINE MONTHS

In the first nine months of the year, total revenue decreased by 13% due to a 26% decrease in sales volumes, partially offset by a 19% increase in realized price.

The total cost of sales (including D&A) decreased 9% ($159 million compared to $174 million in 2013) due to a 26% decrease in sales volume offset by a 25% increase in the average unit cost of sales. The increase in the

2014 THIRD QUARTER REPORT    21

average unit cost of sales was due to higher unit production costs as a result of lower production for UF₆ and UO₂ and the mix of fuel services products sold.

The net effect was an $11 million decrease in gross profit.

NUKEM

	THREE MONTHS ENDED SEPTEMBER 30						CHANGE			NINE MONTHS ENDED SEPTEMBER 30						CHANGE
($ MILLIONS EXCEPT WHERE INDICATED)	2014			2013						2014			2013
Uranium sales (million lbs)		2.5			2.1			19	%		4.7			5.6			(16	)%
Revenue		97			93			4	%		190			276			(31	)%
Cost of product sold (including D&A)		88			100			(12	)%		171			275			(38	)%
Gross profit		9			(7	)		229	%		19			1			1800	%
Net earnings		4			(6	)		167	%		5			(6	)		183	%
Adjustments on derivatives1		—			1			(100	)%		1			(2	)		150	%
NUKEM inventory write-down (reversal) (net of tax)		(1	)		11			(109	)%		(1	)		11			(109	)%
Adjusted net earnings (loss)1		3			6			(50	)%		5			3			67	%

¹  Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (non-IFRS measure, see page 9).

THIRD QUARTER

During the three months ended September 30, 2014, NUKEM delivered 2.5 million pounds of uranium, an increase of 0.4 million pounds due to timing of customer requirements. NUKEM revenues amounted to $97 million compared to $93 million in 2013, due to the increase in deliveries, which more than offset the impact of a decline in the uranium spot price relative to the previous year.

Gross profit amounted to $9 million, compared to a loss of $7 million in the previous year. In the third quarter of 2013, we recorded a charge of $17 million ($11 million after-tax), reflecting a decline in net realizable value of certain inventory. The unit cost of uranium sold was lower in 2014 due to the decline in the spot price. On a percentage basis, gross profits were 10% in 2014 compared to a loss of 7% in the prior year.

Adjusted net earnings for the third quarter of 2014 were $3 million, compared to earnings of $6 million (non-IFRS measure, see page 9) in 2013.

FIRST NINE MONTHS

During the nine months ended September 30, 2014, NUKEM delivered 4.7 million pounds of uranium, a decrease of 0.9 million pounds due to timing of customer requirements and generally lower activity in the market. NUKEM revenues amounted to $190 million due to the decline in deliveries and a lower realized price attributable to the decline in spot price relative to the prior year.

Gross profit amounted to $19 million, compared to $1 million in the first nine months of 2013. The prior year’s margins were impacted by the inventory write-down described above. While sales were significantly lower in the current year, they were at higher margins. On a percentage basis, gross profits were 10% in 2014 compared to nil in the prior year.

Adjusted net earnings for the first nine months of 2014 amounted to $5 million, compared to earnings of $3 million (non-IFRS measure, see page 9) in 2013.

Our operations

Uranium – production overview

Production in our uranium segment this quarter was 0.4 million pounds lower than the third quarter of 2013. Production through the first nine months of the year was 1.1 million pounds lower than the same period in 2013. See below for more information.

22    CAMECO CORPORATION

URANIUM PRODUCTION

CAMECO’S SHARE (MILLION LBS)	THREE MONTHS ENDED SEPTEMBER 30				CHANGE			NINE MONTHS ENDED SEPTEMBER 30				CHANGE			2014 PLAN1
	2014		2013					2014		2013
McArthur River/Key Lake		3.1		3.8		(18	)%		9.0		10.1		(11	)%		12.8
Rabbit Lake		0.9		0.4		125	%		2.0		2.0		—			4.1
Smith Ranch-Highland		0.5		0.5		—			1.5		1.2		25	%		2.0
Crow Butte		0.1		0.2		(50	)%		0.4		0.5		(20	)%		0.6
Inkai		0.8		0.9		(11	)%		2.2		2.4		(8	)%		3.0
Cigar Lake		—		—		—			—		—		—			0.1 - 0.3
Total		5.4		5.8		(7	)%		15.1		16.2		(7	)%		22.6 - 22.8

¹  We previously updated our initial 2014 plan for Cigar Lake (to 0.0 – 0.5 million pounds from 1.0 – 1.5 million pounds) in our Q2 MD&A.

Uranium Q3 updates

Operating properties

McArthur River/Key Lake

Production update

Production for the quarter was 18% lower compared to the same period last year due to a labour disruption in the third quarter that resulted in an unplanned shutdown of the operations for approximately 18 days. Production for the first nine months was 11% lower compared to 2013, primarily for the same reason. As a result, we now expect our share of production this year to be 12.8 million pounds compared to our previous forecast of 13.1 million pounds U₃O₈.

Operations update

The zone 4 north freezewall, and development through the unconformity and into the sandstone, have been completed. Production from the area is now underway.

Labour relations

On October 6, 2014, unionized employees at McArthur River and Key Lake accepted a new four-year contract that includes a 12% wage increase over the term of the agreement. The previous contract expired on December 31, 2013.

Cigar Lake

Production update

We resumed jet bore mining in the first week of September after a temporary suspension in July to allow the ore body to freeze more thoroughly in localized areas. Those areas have now met the desired temperature conditions. Ore slurry is being shipped from the mine to the McClean Lake mill.

Operations update

On October 8, 2014, AREVA’s McClean Lake mill started producing uranium concentrate from ore mined at the Cigar Lake operation.

We now expect to produce between 0.2 million and 0.6 million packaged pounds (100% basis) in 2014, depending on the mine rampup at Cigar Lake and the continued success of milling operations at McClean Lake. We were able to narrow the range from the earlier expectation of up to 1 million packaged pounds (100% basis) as a result of the further experience gained through the commissioning process at the mine and mill, as well as the shorter time remaining in the year. We continue to capitalize costs at Cigar Lake until such time that commercial production is reached. Commercial production is reached when management determines that the mine is able to produce at a consistent or sustainably increasing level.

2014 THIRD QUARTER REPORT    23

We expect to ramp up to our long-term annual production target of 18 million pounds U₃O₈ (100% basis) by 2018.

Caution about forward-looking information relating to Cigar Lake

This discussion of our expectations for Cigar Lake, including our plan for between 0.2 million and 0.6 million packaged pounds (100%) in 2014, and our target annual production of 18 million pounds U₃O₈ at Cigar Lake by 2018 is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the headingCaution about forward-looking information beginning on page 2.

Rabbit Lake

Production update

Production was 125% higher in the third quarter compared to the same period last year as a result of planned timing of production stopes, coupled with slightly improved ore grades. Production in the first nine months was unchanged compared to 2013, and we remain on track to achieve our annual production target.

Smith Ranch-Highland and Crow Butte

Production update

Production was 14% lower for the quarter compared to the same period last year due to a declining head grade at Crow Butte, where there are no new wellfields being developed under the current mine plan. Production in the first nine months was 12% higher compared to 2013 due to the addition of production from the North Butte satellite operation. Our annual production target for 2014 remains unchanged.

Inkai

Production update

Production was 11% lower in the third quarter and 8% lower in the first nine months of 2014 compared to the same periods last year due to delays in bringing on new wellfields as a result of abnormally heavy snowfall and a rapid spring melt earlier in the year.

The operation continues to recover and maintains an annual production forecast of 3.0 million pounds of U₃O₈ (our share).

Fuel services Q3 updates

Port Hope conversion services

Cameco Fuel Manufacturing Inc.

Production update

Fuel services produced 1.1 million kgU in the third quarter, 58% lower than the same period last year. The lower production is primarily due to an extended planned shutdown and lower demand, as well as a lower than expected final delivery from SFL under the toll conversion contract. Production for the first nine months was 8.9 million kgU, 27% lower compared to last year. We decreased our production target, so quarterly production is expected to be lower than in comparable periods in 2013.

We are now expecting to produce between 11 million and 12 million kgU (previously 12 million and 13 million kgU) due to a lower than expected final delivery from SFL under the toll conversion contract.

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

24    CAMECO CORPORATION

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 September 30, 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 September 30, 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 September 30, 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 standards and amendments to existing standards are not yet effective for the period ended September 30, 2014, and have not been applied in preparing the interim financial statements. The following standards and amendments are mandatory for our accounting periods beginning on or after January 1, 2016, unless otherwise noted. We intend to adopt the following amendments to existing standards in our financial statements for the annual period beginning on January 1, 2016, unless otherwise noted and 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 3Business Combinations.

2014 THIRD QUARTER REPORT    25

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 34Interim 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.

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.

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. We intend to adopt IFRS 15 in our financial statements for the annual period beginning January 1, 2017. The extent of the impact of adoption of IFRS 15 has not yet been determined.

26    CAMECO CORPORATION