Report of Foreign Issuer (6-k)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 6-K

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16

Under the Securities Exchange Act of 1934

For the month of October, 2015

Cameco Corporation

(Commission file No. 1-14228)

2121-11th Street West

Saskatoon, Saskatchewan, Canada S7M 1J3

(Address of Principal Executive Offices)

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F ¨ Form 40-F x

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes ¨ No x

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):

Exhibit Index


Exhibit No.	Description	Page No.

99.1	Press Release dated October 30, 2015

99.2	Management’s Discussion & Analysis for the third quarter ending September 30, 2015

99.3	Condensed Consolidated Interim Unaudited Financial Statements for the third quarter ending September 30, 2015

99.4	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 dated October 30, 2015

99.5	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 dated October 30, 2015

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


Date: October 30, 2015	Cameco Corporation
	By:

		“Sean A. Quinn”
		Sean A. Quinn
		Senior Vice-President, Chief Legal Officer and Corporate Secretary

Page 2

Exhibit 99.1

TSX: CCO

NYSE: CCJ

website: cameco.com

currency: Cdn (unless noted)

2121 – 11th Street West, Saskatoon, Saskatchewan, S7M 1J3 Canada

Tel: (306) 956-6200 Fax: (306) 956-6201

Cameco reports third quarter financial results

•

higher consolidated revenue and gross profit for the first nine months

•

lower uranium segment gross profit for the quarter and first nine months

•

annual uranium sales outlook confirmed

•

strong performance at Cigar Lake, increased annual production target range

Saskatoon, Saskatchewan, Canada, October 30, 2015 . . . . . . . . . . . . . . . . . .

Cameco (TSX: CCO; NYSE: CCJ) today reported its consolidated financial and operating results for the third quarter ended September 30, 2015 in accordance with International Financial Reporting Standards (IFRS).

“Our results for the quarter and the first nine months are as expected” said Tim Gitzel, president and CEO, “with a higher proportion of our deliveries scheduled for the fourth quarter.

“We’ve continued to see the oversupply in the market impacting demand and price, and while we can’t control the pace of industry recovery, we can ensure that our company is ready at each step along the way. Our positive long-term view has not changed, so today that means preparing for the demand-driven market we see coming, by keeping our costs down and operating our mines safely and efficiently. Those mines continue to return excellent results, particularly Cigar Lake, which has already exceeded our 2015 production target range. The Cigar Lake operation, along with our other world-class assets, are at the core of our strategy to enhance our operating leverage and maintain the flexibility needed to respond quickly as the market improves.”


	THREE MONTHS									NINE MONTHS
HIGHLIGHTS	ENDED SEPTEMBER 30									ENDED SEPTEMBER 30
($ MILLIONS EXCEPT WHERE INDICATED)	2015			2014			CHANGE			2015			2014		CHANGE
Revenue		649			587			11	%		1,779			1,508		18	%
Gross profit		133			143			(7	)%		415			386		8	%
Net earnings (losses) attributable to equity holders		(4	)		(146	)		97	%		75			113		(34	)%
$ per common share (diluted)		(0.01	)		(0.37	)		97	%		0.19			0.28		(32	)%
Adjusted net earnings (non-IFRS, see page 4)		78			93			(16	)%		193			207		(7	)%
$ per common share (adjusted and diluted)		0.20			0.23			(13	)%		0.49			0.52		(6	)%
Cash provided by (used in) operations (after working capital changes)		(121	)		263			(146	)%		(53	)		244		(122	)%

THIRD QUARTER

Net losses attributable to equity holders this quarter were $4 million ($0.01 per share diluted) compared to net losses of $146 million ($0.37 per share diluted) in the third quarter of 2014. In addition to the items noted below, our net losses were affected by mark-to-market losses on foreign exchange derivatives. Net losses in the third quarter of 2014 included the impairment of our investment in GE-Hitachi Global Laser Enrichment of $184 million and the impairment of our investment in GoviEx Uranium Inc. of $12 million.

On an adjusted basis, our earnings this quarter were $78 million ($0.20 per share diluted) compared to earnings of $93 million ($0.23 per share diluted) (non-IFRS measure, see page 4) in the third quarter of 2014. The change was mainly due to:

•

lower gross profit from our uranium segment

•

lower tax recovery

- 1 -

partially offset by:

•

higher gross profit from our fuel services and NUKEM segments

See Financial results by segment on page 7 for more detailed discussion.

FIRST NINE MONTHS

Net earnings in the first nine months of the year were $75 million ($0.19 per share diluted) compared to earnings of $113 million ($0.28 per share diluted) in the first nine months of 2014. In addition to the items noted below, our net earnings were affected by mark-to-market losses on foreign exchange derivatives. Our 2014 earnings also included a gain on the sale of our interest in BPLP of $127 million, the impairment of our investment in GE-Hitachi Global Laser Enrichment of $184 million and the impairment of our investment in GoviEx Uranium Inc. of $12 million.

On an adjusted basis, our earnings for the first nine months of this year were $193 million ($0.49 per share diluted) compared to earnings of $207 million ($0.52 per share diluted) (non-IFRS measure, see page 4) for the first nine months of 2014. Key variances include:

•

lower gross profit from our uranium segment

•

higher administration costs

•

a favourable settlement of $28 million with respect to a dispute regarding a long-term supply contract with a utility customer recorded in the second quarter of 2014

•

lower tax recovery

partially offset by:

•

higher gross profit from our fuel services and NUKEM segments

•

lower losses from equity accounted investments

Our 2014 adjusted net earnings were also impacted by:

•

an early termination fee of $18 million incurred in 2014 as a result of the cancellation of our toll conversion agreement with Springfields Fuels Ltd., which was to expire in 2016

•

settlement costs of $12 million with respect to the early redemption our Series C debentures recorded in 2014

See Financial results by segment on page 7 for more detailed discussion.

Uranium market update

In the third quarter, there was no significant change to the market in terms of contract volumes or price. Quantities transacted in the spot market were at normal levels, and spot prices remained in the mid-$30s (US). This is in keeping with the rest of the year so far, and is, we believe, simply a function of the currently over-supplied market.

Reactor restarts in Japan remain an important driver of market sentiment in the short term, and the first of these were finally realized: Kyushu’s Sendai unit 1 restarted in August and unit 2 in mid-October. Three additional reactors have been approved by the regulator to restart, and twenty more applications await decisions. We remain confident that a significant number of units will be restarted in Japan over time, though the regulatory approval process and restart schedules are clearly hard to predict.

Longer term, strong fundamentals underpin a positive outlook for the industry. The 65 reactors under construction today and additional units planned over the next decade means increasing uranium demand as those reactors come online. As future supply continues to be negatively affected by current depressed market conditions, we expect to see a shift from the currently over-supplied market we are experiencing today to a demand-driven market that requires more primary supply. Demand growth combined with the timing, development and execution of new supply projects and the continued performance of existing supply, will determine the pace of that shift.

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

This discussion of our expectations for the nuclear industry, including its growth profile, future global uranium supply and demand 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 12.

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Outlook for 2015

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

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

See 2015 Financial results by segment on page 7 for details.

2015 FINANCIAL OUTLOOK

CONSOLIDATED

URANIUM

FUEL SERVICES

NUKEM

Production

—

27.3

million lbs

9 to 10

million kgU

—

Sales volume¹

—

31 to 33

million lbs

Decrease

5% to 10

7 to 8

million lbs U₃O₈

Revenue compared to 2014²

Increase

5% to 10

Increase

5% to 10

%³

Increase

5% to 10

Increase

30% to 35

Average unit cost of sales (including D&A)

—

Increase

5% to
10

%⁴

Increase

5% to 10

Increase

15% to 20

Direct administration costs compared to 2014⁵

Increase

5% to 10

—

Exploration costs compared to 2014

—

Decrease

5% to 10

—

Tax rate⁶

Recovery of

25% to 30

—

Capital expenditures

$385 million

—

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

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

³	Based on a uranium spot price of $36.50 (US) per pound (the Ux spot price as of October 26, 2015), a long-term price indicator of $44.00 (US) per pound (the Ux long-term indicator on October 26, 2015) and an exchange rate of $1.00 (US) for $1.25 (Cdn).

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

⁵	Direct administration costs do not include stock-based compensation expenses.

⁶	Our outlook for the tax rate is based on adjusted net earnings.

We have increased our uranium production outlook to 27.3 million pounds U₃O₈ (previously between 25.3 million and 26.3 million pounds) to reflect the higher expected production from Cigar Lake/McClean Lake. See Uranium 2015 Q3 updates starting on page 11 for more information.

Our outlook for uranium revenue and for fuel services revenue have both changed to an increase of 5% to 10% in each segment (previously an increase up to 5% in each) due to the effects of foreign exchange. We have also adjusted our outlook for NUKEM revenue to an increase of 30% to 35% (previously an increase of 20% to 25%) due to the effects of foreign exchange; however, the higher revenue expectation is largely offset by our adjusted outlook for NUKEM unit cost of sales, which is now expected to increase 15% to 20% (previously an increase of 5% to 10%), also due to the effects of foreign exchange.

We have adjusted our outlook for the consolidated tax rate to a recovery of 25% to 30% (previously 40% to 45%) due to the expected impact of the changes to our revenue outlook noted above, and a change in the distribution of earnings between jurisdictions.

We now expect capital expenditures to be $385 million (previously $405 million). The decrease is primarily due to the timing of expenditures on projects at Key Lake and McArthur River, as well as a reduction in planned spending at Cigar Lake due to changes in the mine plan, slightly offset by increased costs at Inkai and our US operations due to the effect of foreign exchange.

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REVENUE AND EARNINGS SENSITIVITY ANALYSIS

For the rest of 2015:

•

an increase of $5 (US) per pound in both the Ux spot price ($36.50 (US) per pound on October 26, 2015) and the Ux long-term price indicator ($44.00 (US) per pound on October 26, 2015) would increase revenue by $22 million and net earnings by $12 million. Conversely, a decrease of $5 (US) per pound would decrease revenue by $19 million and net earnings by $9 million.

•

a one-cent change in the value of the Canadian dollar versus the US dollar would change adjusted net earnings by $3 million, with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact

ADJUSTED NET EARNINGS (NON-IFRS MEASURE)

Adjusted net earnings is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS measure). We use this measure as a more meaningful way to compare our financial performance from period to period. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance. Adjusted net earnings is our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting period. The adjusted earnings measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period, and has also been adjusted for NUKEM purchase price inventory write-downs and recoveries, income taxes on adjustments, impairment charges on non-producing property, and the after tax gain on the sale of our interest in BPLP.

Adjusted net earnings is non-standard supplemental information and should not be considered in isolation or as a substitute for financial information prepared according to accounting standards. Other companies may calculate this measure differently, so you may not be able to make a direct comparison to similar measures presented by other companies.

The following table reconciles adjusted net earnings with our net earnings.


	THREE MONTHS						NINE MONTHS
	ENDED SEPTEMBER 30						ENDED SEPTEMBER 30
($ MILLIONS)	2015			2014			2015			2014
Net earnings (losses) attributable to equity holders		(4	)		(146	)		75			113

Adjustments
Adjustments on derivatives (pre-tax)		112			60			157			37
NUKEM purchase price inventory recovery		—			(2	)		(3	)		(2	)
Impairment charge		—			196			6			196
Income taxes on adjustments		(30	)		(15	)		(42	)		(10	)
Gain on interest in BPLP (after tax)		—			—			—			(127	)

Adjusted net earnings		78			93			193			207

Discontinued operation

On March 27, 2014, we completed the sale of our 31.6% limited partnership interest in BPLP, which was accounted for effective January 1, 2014. The aggregate sale price for our interest in BPLP and certain related entities was $450 million. We realized an after tax gain of $127 million on this divestiture. As a result of the transaction, we presented the results of BPLP as a discontinued operation and we revised our statement of earnings, statement of comprehensive income and statement of cash flows to reflect the change in presentation. See note 4 to the interim financial statements for more information.

TRANSFER PRICING DISPUTES

We have been reporting on our transfer pricing disputes with Canada Revenue Agency (CRA) since 2008, when it originated, and with the United States Internal Revenue Service (IRS) since the first quarter of 2015. Below, we discuss the general nature of transfer pricing disputes and, more specifically, the ongoing disputes we have.

Transfer pricing is a complex area of tax law, and it is difficult to predict the outcome of cases like ours. However, tax authorities generally test two things:

•

the governance (structure) of the corporate entities involved in the transactions

•

the price at which goods and services are sold by one member of a corporate group to another

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We have a global customer base and we established a marketing and trading structure involving foreign subsidiaries, including Cameco Europe Limited (CEL), which entered into various intercompany arrangements, including purchase and sale agreements, as well as uranium purchase and sale agreements with third parties. Cameco and its subsidiaries made reasonable efforts to put arm’s length transfer pricing arrangements in place, and these arrangements expose the parties to the risks and rewards accruing to them under these contracts. The intercompany contract prices are generally comparable to those established in comparable contracts between arm’s-length parties entered into at that time.

For the years 2003 to 2009, CRA has shifted CEL’s income (as re-calculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2009, transfer pricing penalties. The IRS also allocated a portion of CEL’s income for 2009 to the US, resulting in such income being taxed in multiple jurisdictions. Taxes of approximately $290 million for the 2003 – 2014 years have already been paid in a jurisdiction outside Canada and the US. Bilateral international tax treaties contain provisions that generally seek to prevent taxation of the same income in both countries. As such, in connection with these disputes, we are considering our options including remedies under international tax treaties that would limit double taxation; however, there is a risk that we will not be successful in eliminating all potential double taxation. The expected income adjustments under our tax disputes are represented by the amounts claimed by CRA and IRS and are described below.

CRA dispute

Since 2008, CRA has disputed our corporate structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2009 tax returns. We have recorded a cumulative tax provision of $92 million, where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through September 30, 2015. We are confident that we will be successful in our case and continue to believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

For the years 2003 through 2009, CRA issued notices of reassessment for approximately $2.8 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $820 million. We expect to receive the reassessment for 2010 in the fourth quarter. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229 million. The Canadian income tax rules include provisions that require larger companies like us to remit 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions and tax loss carryovers, we have paid a net amount of $229 million cash to the Government of Canada, which includes the amounts shown in the table below.


	CASH			INTEREST AND		TRANSFER PRICING
YEAR PAID ($ MILLIONS)	TAXES			INSTALMENT PENALTIES		PENALTIES		TOTAL
Prior to 2013		—			13		—		13
2013		1			9		36		46
2014		106			47		—		153
2015		(63	)		1		79		17
Total		44			70		115		229

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

- 5 -

Under the Canadian federal and provincial tax rules, the amount required to be paid or secured each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers. Recently, the CRA decided to disallow the use of any loss carry-backs for any transfer pricing adjustment, starting with the 2008 tax year. This will not change the total amount shown in the table below as paid, secured or owing, but it does change the distribution among years. As an alternative to paying cash, we expect to be able to provide security in the form of letters of credit to satisfy our requirements. We have updated the table below to reflect the potential use of letters of credit. The estimated amounts summarized in the table below reflect actual amounts paid or secured and estimated future amounts owing based on the actual and expected reassessments for the years 2003 through 2014, and include the expected adjustment for the inability to use loss carry-backs starting in 2008. We will update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2014.


$ MILLIONS	2003 - 2014		2015		2016 - 2017		2018 - 2023		TOTAL
50% of cash taxes and transfer pricing penalties paid, secured or owing in the period¹
Cash payments		143		35 - 60		155 - 180		0		335 - 360
Potential letters of credit		0		255 - 280		95 - 120		15 - 40		380 - 400
Total paid		143		295 - 320		255 - 280		15 - 40		725 - 750

¹	These amounts do not include interest and instalment penalties, which totalled approximately $70 million to September 30, 2015.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to the Government of Canada, including the $229 million already paid to date.

We are expecting the trial for the 2003, 2005 and 2006 reassessments to commence during the week of September 26, 2016 and to conclude within four months thereafter. If this timing is adhered to, we expect to receive a Tax Court decision within six to 18 months after the trial is complete.

IRS dispute

In the first quarter, we received a Revenue Agent’s Report (RAR) from the IRS challenging the transfer pricing used under certain intercompany transactions pertaining to the 2009 tax year for certain of our US subsidiaries. The RAR lists the adjustments proposed by the IRS and calculates the tax and any penalties owing based on the proposed adjustments.

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

•

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

•

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

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

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

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

We believe that the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

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

This discussion of our expectations relating to our tax disputes with CRA and IRS and future tax reassessments by CRA and IRS is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 12 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.

- 6 -

Assumptions

•

CRA will reassess us for the years 2010 through 2014 using a similar methodology as for the years 2003 through 2009, and the reassessments will be issued on the basis we expect

•

we will be able to apply elective deductions to the extent anticipated

•

we will be able to utilize letters of credit to the extent anticipated

•

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

•

we will be substantially successful in our dispute with CRA and the cumulative tax provision of $92 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date

•

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

•

we will be substantially successful in our dispute with IRS

Material risks that could cause actual results to differ materially

•

CRA reassesses us for years 2010 through 2014 using a different methodology than for years 2003 through 2009, or we are unable to apply elective deductions or utilize letters of credit to the same extent as anticipated, resulting in the required cash payments to CRA pending the outcome of the dispute being higher than expected

•

the time lag for the reassessments for each year is different than we currently expect

•

we are unsuccessful and the outcomes of our dispute with CRA and/or IRS result in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision, which could have a material adverse effect on our liquidity, financial position, results of operations and cash flows

•

cash tax payable increases due to unanticipated adjustments by CRA or IRS not related to transfer pricing

•

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

•

we are unable to effectively eliminate all double taxation

Financial results by segment

Uranium


				THREE MONTHS							NINE MONTHS
				ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
HIGHLIGHTS				2015		2014		CHANGE			2015		2014		CHANGE
Production volume (million lbs)					8.2		5.4		52	%		18.7		15.1		24	%
Sales volume (million lbs)¹					6.9		9.0		(23	)%		21.2		23.3		(9	)%
Average spot price	($	US/lb	)		36.21		31.80		14	%		36.91		31.90		16	%
Average long-term price	($	US/lb	)		44.17		44.33		—			47.06		45.94		2	%
Average realized price	($	US/lb	)		43.61		45.87		(5	)%		44.57		46.14		(3	)%
	($	Cdn/lb	)		56.07		49.83		13	%		55.65		50.35		11	%
Average unit cost of sales (including D&A)	($	Cdn/lb	)		40.16		35.09		14	%		39.13		34.81		12	%
Revenue ($ millions)¹					388		447		(13	)%		1,179		1,171		1	%
Gross profit ($ millions)					110		132		(17	)%		350		362		(3	)%
Gross profit (%)					28		30		(7	)%		30		31		(3	)%

Includes sales and revenue between our uranium, fuel services and NUKEM segments (nil pounds in sales and nil revenue in Q3, 2015; 802,000 pounds and revenue of $28.0 million in Q3, 2014; 15,000 pounds in sales and revenue of $0.5 million in the first nine months of 2015; 967,000 pounds and revenue of $33.0 million in the first nine months of 2014).

THIRD QUARTER

Production volumes this quarter were 52% higher compared to the third quarter of 2014, mainly due to production from Cigar Lake and higher production from McArthur River/Key Lake, Rabbit Lake and Inkai, which was partially offset by lower production at our US operations. See Uranium 2015 Q3 updates starting on page 11 for more information.

The 13% decrease in uranium revenues was a result of a 23% decrease in sales volume, partially offset by a 13% increase in the Canadian dollar average realized price.

The US dollar average realized price decreased by 5% compared to 2014 mainly due to lower prices on fixed price contracts, while the higher Canadian dollar realized prices this quarter were a result of the weakening of the Canadian dollar compared to 2014. This quarter the exchange rate on the average realized price was $1.00 (US) for $1.29 (Cdn) compared to $1.00 (US) for $1.09 (Cdn) in the third quarter of 2014.

Total cost of sales (including D&A) decreased by 12% ($278 million compared to $315 million in 2014) due to a 23% decrease in sales volume, partially offset by a 14% increase in the unit cost of sales. The increase in the unit cost of sales was mainly the result of an increase in the volume of material purchased in the quarter at prices higher than our average cost of inventory and an increase in unit production costs related to the addition of higher cost production from Cigar Lake during ramp up.

- 7 -

The net effect was a $22 million decrease in gross profit for the quarter.

FIRST NINE MONTHS

Production volumes for the first nine months of the year were 24% higher than in the previous year due to the addition of production from Cigar Lake and higher production at McArthur/Key Lake, and Rabbit Lake, partially offset by lower production at our US operations. See Uranium 2015 Q3 updates starting on page 11 for more information.

Uranium revenues increased 1% compared to the first nine months of 2014 due to an 11% increase in the Canadian dollar average realized price, partially offset by a 9% decrease in sales volumes in the first nine months.

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 2015 uranium sales targets, and, therefore, expect to deliver between 10 million and 12 million pounds in the fourth quarter.

Our Canadian dollar realized prices for the first nine months of 2015 were higher than 2014, primarily as a result of the weakening of the Canadian dollar compared to 2014. For the first nine months of 2015, the exchange rate on the average realized price was $1.00 (US) for $1.25 (Cdn) compared to $1.00 (US) for $1.09 (Cdn) for the same period in 2014.

Total cost of sales (including D&A) increased by 2% ($829 million compared to $810 million in 2014) mainly due to a 12% increase in the unit cost of sales, partially offset by a 9% decrease in sales volume for the first nine months. The increase in the unit cost of sales was mainly the result of an increase in the volume of material purchased in the first nine months at prices higher than our average cost of inventory, and an increase in unit production costs related to the addition of higher cost production from Cigar Lake during rampup.

The net effect was a $12 million decrease in gross profit for the first nine months.

We are active in the uranium market, buying and selling uranium on the spot market and under long-term contracts when we expect it will be beneficial for us. Purchases are impacted by foreign exchange rates, and may, in some cases, require we pay prices higher or lower than current spot prices. Depending on the volume and unit cost of purchases in a quarter, our average cost of inventory can be impacted, which flows through to our cost of sales.

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.


	THREE MONTHS							NINE MONTHS
	ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
($CDN/LB)	2015		2014		CHANGE			2015		2014		CHANGE
Produced
Cash cost		17.56		17.91		(2	)%		22.97		21.19		8	%
Non-cash cost		9.53		7.31		30	%		11.79		10.47		13	%

Total production cost		27.09		25.22		7	%		34.76		31.66		10	%

Quantity produced (million lbs)		8.2		5.4		52	%		18.7		15.1		24	%

Purchased
Cash cost		47.19		30.91		53	%		46.83		37.25		26	%

Quantity purchased (million lbs)		2.7		1.8		50	%		9.3		3.4		174	%

Totals
Produced and purchased costs^{1, 2}		32.07		26.64		20	%		38.77		32.69		19	%

Quantities produced and purchased (million lbs)		10.9		7.2		51	%		28.0		18.5		51	%

¹	This quarter, cash costs of purchased material were $37.78 US per pound compared to $27.98 US per pound in the same period in 2014. In the third quarter the exchange rate on purchases averaged $1.00 (US) for $1.25 (Cdn) compared to $1.00 (US) for $1.10 (Cdn) in the third quarter of 2014.

For the first nine months, cash costs of purchased material were $37.51 US per pound compared to $33.89 per lb in the same period in 2014. For the first nine months of 2015, the exchange rate on purchases averaged $1.00 (US) for $1.25 (Cdn) compared to $1.00 (US) for $1.10 (Cdn) for the same period in 2014.

- 8 -

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 third quarter and the first nine months of 2015 and 2014.

Cash and total cost per pound reconciliation


	THREE MONTHS						NINE MONTHS
	ENDED SEPTEMBER 30						ENDED SEPTEMBER 30
($ MILLIONS)	2015			2014			2015			2014
Cost of product sold		205.5			248.2			660.9			633.8
Add / (subtract)
Royalties		(31.3	)		(21.5	)		(67.0	)		(56.7	)
Standby charges		—			(5.8	)		—			(24.8	)
Other selling costs		(1.9	)		(1.2	)		(7.1	)		(6.7	)
Change in inventories		99.1			(67.3	)		278.1			(99.0	)

Cash operating costs (a)		271.4			152.4			864.9			446.6
Add / (subtract)
Depreciation and amortization		72.2			66.7			168.2			175.9
Change in inventories		6.0			(27.3	)		52.5			(17.7	)

Total operating costs (b)		349.6			191.8			1,085.6			604.8

Uranium produced & purchased (million lbs) (c)		10.9			7.2			28.0			18.5

Cash costs per pound (a ÷ c)		24.90			21.17			30.89			24.14
Total costs per pound (b ÷ c)		32.07			26.64			38.77			32.69

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)


				THREE MONTHS							NINE MONTHS
				ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
HIGHLIGHTS				2015		2014		CHANGE			2015		2014		CHANGE
Production volume (million kgU)					0.6		1.1		(45	)%		6.3		8.9		(29	)%
Sales volume (million kgU)					3.8		3.1		23	%		9.1		8.2		11	%
Average realized price	($	Cdn/kgU	)		22.22		23.11		(4	)%		24.11		22.21		9	%
Average unit cost of sales (including D&A)	($	Cdn/kgU	)		18.75		21.55		(13	)%		19.71		19.46		1	%
Revenue ($ millions)					83		71		17	%		220		182		21	%
Gross profit ($ millions)					13		5		160	%		40		23		74	%
Gross profit (%)					16		7		129	%		18		13		38	%

THIRD QUARTER

Total revenue for the third quarter of 2015 increased to $83 million from $71 million for the same period last year. A 23% increase in sales volumes was partially offset by a 4% decrease in average realized price, primarily due to the mix of products sold, partially offset by the weakening of the Canadian dollar compared to 2014.

- 9 -

The total cost of products and services sold (including D&A) increased by 6% ($70 million compared to $66 million in the third quarter of 2014) due to the increase in sales volumes, partially offset by a decrease in the average unit cost of sales. When compared to 2014, the average unit cost of sales was 13% lower due to the mix of fuel services products sold, partially offset by higher production costs.

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

FIRST NINE MONTHS

In the first nine months of the year, total revenue increased by 21% due to an 11% increase in sales volumes and a 9% increase in realized price that was the result of the weakening of the Canadian dollar and the mix of products sold.

The total cost of sales (including D&A) increased 13% ($180 million compared to $159 million in 2014) due to an increase in sales volume and a 1% increase in the average unit cost of sales, which resulted from increased production costs, partially offset by the mix of fuel services products sold.

The net effect was a $17 million increase in gross profit.

NUKEM


				THREE MONTHS							NINE MONTHS
				ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
HIGHLIGHTS				2015		2014		CHANGE			2015		2014		CHANGE
Uranium sales (million lbs)¹					2.9		2.5		16	%		6.9		4.7		47	%
Average realized price	($	Cdn/lb	)		52.70		38.52		37	%		46.97		39.72		18	%
Cost of product sold (including D&A)					170		88		93	%		326		171		91	%
Revenue ($ millions)¹					183		97		89	%		361		190		90	%
Gross profit ($ millions)					14		9		56	%		35		19		84	%
Gross profit (%)					8		9		(11	)%		10		10		—

¹	Includes sales and revenue between our uranium, fuel services and NUKEM segments (130,000 pounds in sales and revenue of $6.0 million in Q3, 2015, nil in Q3, 2014; 873,000 pounds in sales and revenue of $19.3 million in the first nine months of 2015, nil in the first nine months of 2014).

THIRD QUARTER

During the third quarter of 2015, NUKEM delivered 2.9 million pounds of uranium, an increase of 16% from the same period last year. Total revenues increased by 89% as a result of higher sales volumes and average realized prices which were 37% higher than those realized in the third quarter of 2014.

Gross profit percentage was 8% in the third quarter of 2015, a slight increase from 9% recorded in the third quarter of 2014. The allocation of the historic purchase price to the sale of inventory on hand at the time of acquisition of NUKEM, impacted margins for the quarter.

The net effect was a $5 million increase in gross profit.

FIRST NINE MONTHS

During the nine months ended September 30, 2015, NUKEM delivered 6.9 million pounds of uranium, an increase of 47%, due to timing of customer requirements and generally lower activity in the market during 2014. Total revenues increased 90% due to a 47% increase in sales volumes and an 18% increase in average realized price.

Gross profit percentage was 10% for the first nine months of 2015, unchanged from the same period in 2014. Included in the 2014 margin was a $6 million write-down of inventory compared to a $3 million recovery in 2015. The write-down in 2014 was a result of a decline in the spot price during the period.

The net effect was a $16 million increase in gross profit.

- 10 -

Uranium 2015 Q3 updates

URANIUM PRODUCTION


	THREE MONTHS							NINE MONTHS
	ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
OUR SHARE (MILLION LBS)	2015		2014		CHANGE			2015		2014		CHANGE			2015 PLAN
McArthur River/Key Lake		3.9		3.1		26	%		9.5		9.0		6	%		13.7
Cigar Lake		1.8		—		—			3.3		—		—			5.0
Inkai		1.0		0.8		25	%		2.2		2.2		—			3.0
Rabbit Lake		1.1		0.9		22	%		2.2		2.0		10	%		3.9
Smith Ranch-Highland		0.3		0.5		(40	)%		1.2		1.5		(20	)%		1.4
Crow Butte		0.1		0.1		—			0.3		0.4		(25	)%		0.3
Total		8.2		5.4		52	%		18.7		15.1		24	%		27.3

MCARTHUR RIVER/KEY LAKE

Production for the quarter was 26% higher compared to the same period last year and 6% higher for the first nine months due to the timing of mill maintenance.

At Key Lake, commissioning of the new calciner is underway and expected to be complete by year end. The existing calciner circuit will remain in place until operational reliability of the new calciner is achieved. The operation remains on track to achieve our planned 2015 production; however, operational tie-ins of the new calciner will require brief production outages in the fourth quarter, and the output of the mill will be sensitive to the performance of the calciners.

CIGAR LAKE

During the third quarter, Cigar Lake packaged approximately 3.6 million pounds (100% basis, 1.8 million pounds our share) for total production of 6.7 million pounds (100% basis, 3.3 million pounds our share) to the end of September. As of the end of October, the mill has packaged over 8 million pounds (100% basis) and exceeded the 2015 production target range.

If production continues at current rates, the McClean Lake mill could produce more than 10 million packaged pounds of uranium (100% basis, 5 million pounds our share) from Cigar Lake in 2015. As we ramp up production to 18 million pounds (100% basis) by 2018, volumes may not be linear year-to-year, but will vary based on our operational experience. To ensure the most efficient operation of the mine and mill throughout the year, we expect to continually manage ore supply and, therefore, may halt and resume mining several times during a quarter without impacting planned annual production.

INKAI

Production for the quarter was 25% higher compared to the same period last year due to the timing of new wellfield development. Production remains unchanged for the first nine months of the year compared to the same periods in 2014. The operation remains on track to achieve our planned 2015 production.

Qualified persons

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

- 11 -

MCARTHUR RIVER/KEY LAKE

•

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

CIGAR LAKE

•

Les Yesnik, general manager, Cigar Lake, Cameco

INKAI

•

Darryl Clark, general director, JV Inkai

Caution about forward-looking information

This document 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 document as forward-looking information.

Key things to understand about the forward-looking information in this document:

•

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 pages 12 and 13, 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 page 12. We recommend you also review our annual information form, first quarter, second quarter and third quarter MD&A, 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 document

•

our expectations about 2015 and future global uranium supply and demand including the discussion under the heading Uranium market update

•

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

•

our expectations for uranium deliveries in the fourth quarter

•

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

Material risks

•

actual sales volumes or market prices for any of our products or services are lower than we expect for any reason, including changes in market prices or loss of market share to a competitor

•

we are adversely affected by changes in foreign currency exchange rates, interest rates or tax rates

•

our production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms

•

our estimates of production, purchases, costs, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate

•

we are unable to enforce our legal rights under our existing agreements, permits or licences

•

we are subject to litigation or arbitration that has an adverse outcome, including lack of success in our disputes with tax authorities

•

we are unsuccessful in our dispute with CRA and this results in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision

•

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

•

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

•

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

•

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

•

we are affected by political risks

•

we are affected by terrorism, sabotage, blockades, civil unrest, social or political activism, accident or a deterioration in political support for, or demand for, nuclear energy

•

we are impacted by changes in the regulation or public perception of the safety of nuclear power plants, which adversely affect the construction of new plants, the relicensing of existing plants and the demand for uranium

•

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

•

our uranium suppliers fail to fulfil delivery commitments

•

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

•

our Cigar Lake development, mining or production plans are delayed or do not succeed, including as a result of any difficulties with the jet boring mining method or freezing the deposit to meet production targets, or any difficulties with the McClean Lake mill modifications or expansion or milling of Cigar Lake ore

- 12 -

•

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 suppliers’, 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

•

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

•

our expectations about the outcome of disputes with tax authorities

•

our decommissioning and reclamation expenses

•

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

•

the geological, hydrological and other conditions at our mines

•

our McArthur River development, mining and production plans succeed

•

our Cigar Lake development, mining and production plans succeed, the jet boring mining method works as anticipated, and the deposit freezes as planned

•

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

•

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

Conference call

We invite you to join our third quarter conference call on Monday, November 2, 2015 at 11:00 a.m. Eastern.

The call will be open to all investors and the media. To join the call, please dial (800) 769-8320 (Canada and US) or (416) 340-8530. An operator will put your call through. A live audio feed of the conference call will be available from a link at cameco.com. See the link on our home page on the day of the call.

A recorded version of the proceedings will be available:

•

on our website, cameco.com, shortly after the call

•

on post view until midnight, Eastern, December 6, 2015, by calling (800) 408-3053 (Canada and US) or (905) 694-9451 (Passcode 5846753#)

Additional information

You can find a copy of our third quarter MD&A and interim financial statements on our website at cameco.com, on SEDAR at sedar.com and on EDGAR at sec.gov/edgar.shtml.

- 13 -

Additional information, including our 2014 annual management’s discussion and analysis, annual audited financial statements and annual information form, is available on SEDAR at sedar.com, on EDGAR at sec.gov/edgar.shtml and on our website at cameco.com.

Profile

We are one of the world’s largest uranium producers, a significant supplier of conversion services and one of two CANDU fuel manufacturers in Canada. Our competitive position is based on our controlling ownership of the world’s largest high-grade reserves and low-cost operations. Our uranium products are used to generate clean electricity in nuclear power plants around the world. We also explore for uranium in the Americas, Australia and Asia. Our shares trade on the Toronto and New York stock exchanges. Our head office is in Saskatoon, Saskatchewan.

As used in this news release, the terms we, us, our, the Company and Cameco mean Cameco Corporation and its subsidiaries; including NUKEM Energy GmbH, unless otherwise indicated.

- End -



Investor inquiries:		Rachelle Girard (306) 956-6403

Media inquiries:		Gord Struthers (306) 956-6593

- 14 -

Exhibit 99.2

LOGO

Management’s discussion and analysis

for the quarter ended September 30, 2015


THIRD QUARTER UPDATE			4

CONSOLIDATED FINANCIAL RESULTS			8

OUTLOOK FOR 2015			15

LIQUIDITY AND CAPITAL RESOURCES			17

FINANCIAL RESULTS BY SEGMENT

URANIUM			19

FUEL SERVICES			21

NUKEM			22

OUR OPERATIONS

URANIUM 2015 Q3 UPDATES			23

FUEL SERVICES 2015 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, 2015 (interim financial statements). The information is based on what we knew as of October 30, 2015 and updates our first quarter, second quarter and annual MD&A included in our 2014 annual report.

As you review this MD&A, we encourage you to read our interim financial statements as well as our audited consolidated financial statements and notes for the year ended December 31, 2014 and annual MD&A. You can find more information about Cameco, including our audited consolidated financial statements and our most recent annual information form, on our website at cameco.com, on SEDAR at sedar.com or on EDGAR at sec.gov. You should also read our annual information form before making an investment decision about our securities.

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

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

Throughout this document, the terms we, us, our and Cameco mean Cameco Corporation and its subsidiaries, including NUKEM Energy Gmbh (NUKEM), unless otherwise indicated.

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 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, first quarter, second quarter and annual MD&A, which includes a discussion of other material risks that could cause actual results to differ significantly from our current expectations.

•

Examples of forward-looking information in this MD&A

•

the discussion under the heading Our strategy

•

our expectations about 2015 and future global uranium supply and demand including the discussion under the heading Uranium market update

•

our expectations for uranium deliveries in the fourth quarter

•

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

•

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

•

our price sensitivity analysis for our uranium segment

•

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

•

our expectation that our operating and investment activities for the remainder of 2015 will not be constrained by the financial-related covenants in our unsecured revolving credit facility

•

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

Material risks

•

actual sales volumes or market prices for any of our products or services are lower than we expect for any reason, including changes in market prices or loss of market share to a competitor

•

we are adversely affected by changes in foreign currency exchange rates, interest rates or tax rates

•

our production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms

•

our estimates of production, purchases, costs, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate

•

we are unable to enforce our legal rights under our existing agreements, permits or licences

•

we are subject to litigation or arbitration that has an adverse outcome, including lack of success in our disputes with tax authorities

•

we are unsuccessful in our dispute with CRA and this results in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision

•

we are unable to utilize letters of credit to the extent anticipated in our dispute with CRA

•

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

•

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

•

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

•

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

•

we are affected by political risks

•

we are affected by terrorism, sabotage, blockades, civil unrest, social or political activism, accident or a deterioration in political support for, or demand for, nuclear energy

•

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

•

our uranium suppliers fail to fulfil delivery commitments

•

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

•

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

2 CAMECO CORPORATION

•

our operations are disrupted due to problems with our own or our suppliers’ or 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 expected production level and production costs

•

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

•

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

•

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

•

our expectations about the outcome of disputes with tax authorities

•

we are able to utilize letters of credit to the extent anticipated in our dispute with CRA

•

our decommissioning and reclamation expenses

•

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

•

the geological, hydrological and other conditions at our mines

•

our McArthur River development, mining and production plans succeed

•

our Cigar Lake development, mining and production plans succeed, the jet boring mining method works as anticipated, and the deposit freezes as planned

•

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

•

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

•

2015 THIRD QUARTER REPORT 3

Our strategy

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

We plan to:

•

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

•

ensure continued reliable, low-cost production at Inkai

•

successfully ramp up production at Cigar Lake

•

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

•

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

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

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 was accounted for as being completed effective January 1, 2014.

Under IFRS, we are required to report the results from discontinued operations separately from continuing operations. 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


	THREE MONTHS									NINE MONTHS
HIGHLIGHTS	ENDED SEPTEMBER 30									ENDED SEPTEMBER 30
($ MILLIONS EXCEPT WHERE INDICATED)	2015			2014			CHANGE			2015			2014		CHANGE
Revenue		649			587			11	%		1,779			1,508		18	%
Gross profit		133			143			(7	)%		415			386		8	%
Net earnings (losses) attributable to equity holders		(4	)		(146	)		97	%		75			113		(34	)%
$ per common share (diluted)		(0.01	)		(0.37	)		97	%		0.19			0.28		(32	)%
Adjusted net earnings (non-IFRS, see page 9)		78			93			(16	)%		193			207		(7	)%
$ per common share (adjusted and diluted)		0.20			0.23			(13	)%		0.49			0.52		(6	)%
Cash provided by (used in) operations (after working capital changes)		(121	)		263			(146	)%		(53	)		244		(122	)%

THIRD QUARTER

On an adjusted basis, our earnings this quarter were $78 million ($0.20 per share diluted) compared to earnings of $93 million ($0.23 per share diluted) (non-IFRS measure, see page 9) in the third quarter of 2014. The change was mainly due to:

•

lower gross profit from our uranium segment

•

lower tax recovery

4 CAMECO CORPORATION

partially offset by:

•

higher gross profit from our fuel services and NUKEM segments

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

FIRST NINE MONTHS

On an adjusted basis, our earnings for the first nine months of this year were $193 million ($0.49 per share diluted) compared to earnings of $207 million ($0.52 per share diluted) (non-IFRS measure, see page 9) for the first nine months of 2014. Key variances include:

•

lower gross profit from our uranium segment

•

higher administration costs

•

a favourable settlement of $28 million with respect to a dispute regarding a long-term supply contract with a utility customer recorded in the second quarter of 2014

•

lower tax recovery

partially offset by:

•

higher gross profit from our fuel services and NUKEM segments

•

lower losses from equity accounted investments

Our 2014 adjusted net earnings were also impacted by:

•

an early termination fee of $18 million incurred in 2014 as a result of the cancellation of our toll conversion agreement with Springfields Fuels Ltd., which was to expire in 2016

•

settlement costs of $12 million with respect to the early redemption our Series C debentures recorded in 2014

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

Operations update


				THREE MONTHS							NINE MONTHS
				ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
HIGHLIGHTS				2015		2014		CHANGE			2015		2014		CHANGE
Uranium	Production volume (million lbs)				8.2		5.4		52	%		18.7		15.1		24	%
	Sales volume (million lbs)¹				6.9		9.0		(23	)%		21.2		23.3		(9	)%
	Average realized price	($US/lb	)		43.61		45.87		(5	)%		44.57		46.14		(3	)%
		($Cdn/lb	)		56.07		49.83		13	%		55.65		50.35		11	%
	Revenue ($ millions)¹				388		447		(13	)%		1,179		1,171		1	%
	Gross profit ($ millions)				110		132		(17	)%		350		362		(3	)%
Fuel services	Production volume (million kgU)				0.6		1.1		(45	)%		6.3		8.9		(29	)%
	Sales volume (million kgU)				3.8		3.1		23	%		9.1		8.2		11	%
	Average realized price	($Cdn/kgU	)		22.22		23.11		(4	)%		24.11		22.21		9	%
	Revenue ($ millions)				83		71		17	%		220		182		21	%
	Gross profit ($ millions)				13		5		160	%		40		23		74	%
NUKEM	Uranium sales (million lbs)¹				2.9		2.5		16	%		6.9		4.7		47	%
	Average realized price	($Cdn/lb	)		52.70		38.52		37	%		46.97		39.72		18	%
	Revenue ($ millions)¹				183		97		89	%		361		190		90	%
	Gross profit ($ millions)				14		9		56	%		35		19		84	%

¹	Includes sales and revenue between our uranium, fuel services and NUKEM segments. Please see Financial results by segment beginning on page 19.

2015 THIRD QUARTER REPORT 5

Production in our uranium segment this quarter was 52% higher compared to the third quarter of 2014, mainly due to production from Cigar Lake and higher production from McArthur River/Key Lake, Rabbit Lake and Inkai, partially offset by lower production from our US operations. See Uranium 2015 Q3 updates starting on page 23 for more information.

Production in our fuel services segment was 45% lower this quarter than in the third quarter of 2014 due to lower planned annual production in 2015.

Key highlights:

•

During the first nine months of the year, the McClean Lake mill packaged 6.7 million pounds of Cigar Lake uranium (100% basis, 3.3 million pounds our share) and as of the end of October, the mill has now packaged over 8 million pounds (100% basis) and exceeded the 2015 production target range. If production continues at current rates, the McClean Lake mill could produce more than 10 million packaged pounds of uranium (100% basis, 5 million pounds our share) from Cigar Lake in 2015.

Uranium market update

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

6 CAMECO CORPORATION

Industry prices at quarter end


	SEP 30		JUN 30		MAR 31		DEC 31		SEP 30		JUN 30
	2015		2015		2015		2014		2014		2014
Uranium ($US/lb U₃O₈)¹
Average spot market price		36.38		36.38		39.45		35.50		35.40		28.23
Average long-term price		44.00		46.00		49.50		49.50		45.00		44.50

Fuel services ($US/kgU as UF₆)¹
Average spot market price
North America		7.00		7.50		7.50		8.25		7.25		7.25
Europe		7.50		8.00		8.00		8.63		7.50		7.50
Average long-term price
North America		15.00		16.00		16.00		16.00		16.00		16.00
Europe		16.25		17.00		17.00		17.00		17.00		17.00

Note: the industry does not publish UO₂ prices.

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

On the spot market, where purchases call for delivery within one year, the volume reported by Ux Consulting (UxC) for the third quarter of 2015 was approximately 10 million pounds. This compares to approximately 13 million pounds in the third quarter of 2014. For the first nine months of the year, UxC has reported a total of about 36 million pounds transacted, compared to a three-year average of about 35 million pounds over that period each year.

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).At the end of the quarter, the average reported spot price was $36.38 (US) per pound, in line with the previous quarter. The average reported long-term price declined $2.00 (US) to $44.00 (US) per pound from the previous quarter.

Spot and long-term UF₆ conversion prices declined during the quarter.

Shares and stock options outstanding

At October 29, 2015, we had:

•

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

•

8,596,581 stock options outstanding, with exercise prices ranging from $19.30 to $54.38

Dividend policy

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

2015 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


	THREE MONTHS									NINE MONTHS
HIGHLIGHTS	ENDED SEPTEMBER 30									ENDED SEPTEMBER 30
($ MILLIONS EXCEPT WHERE INDICATED)	2015			2014			CHANGE			2015			2014		CHANGE
Revenue		649			587			11	%		1,779			1,508		18	%
Gross profit		133			143			(7	)%		415			386		8	%
Net earnings (losses) attributable to equity holders		(4	)		(146	)		97	%		75			113		(34	)%
$ per common share (basic)		(0.01	)		(0.37	)		97	%		0.19			0.28		(32	)%
$ per common share (diluted)		(0.01	)		(0.37	)		97	%		0.19			0.28		(32	)%
Adjusted net earnings (non-IFRS, see page 9)		78			93			(16	)%		193			207		(7	)%
$ per common share (adjusted and diluted)		0.20			0.23			(13	)%		0.49			0.52		(6	)%
Cash provided by (used in) operations (after working capital changes)		(121	)		263			(146	)%		(53	)		244		(122	)%

NET EARNINGS

On an adjusted basis, our earnings this quarter were $78 million ($0.20 per share diluted) compared to earnings of $93 million ($0.23 per share diluted) (non-IFRS measure, see page 9) in the third quarter of 2014. The change was mainly due to:

•

lower gross profit from our uranium segment

•

lower tax recovery

partially offset by:

•

higher gross profit from our fuel services and NUKEM segments

On an adjusted basis, our earnings for the first nine months of this year were $193 million ($0.49 per share diluted) compared to earnings of $207 million ($0.52 per share diluted) (non-IFRS measure, see page 9) for the first nine months of 2014. Key variances include:

•

lower gross profit from our uranium segment

•

higher administration costs

•

a favourable settlement of $28 million with respect to a dispute regarding a long-term supply contract with a utility customer recorded in the second quarter of 2014

•

lower tax recovery

partially offset by:

•

higher gross profit from our fuel services and NUKEM segments

•

lower losses from equity accounted investments

Our 2014 adjusted net earnings were also impacted by:

•

an early termination fee of $18 million incurred in 2014 as a result of the cancellation of our toll conversion agreement with Springfields Fuels Ltd., which was to expire in 2016

8 CAMECO CORPORATION

•

settlement costs of $12 million with respect to the early redemption our Series C debentures recorded in 2014

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

ADJUSTED NET EARNINGS (NON-IFRS MEASURE)

The following table reconciles adjusted net earnings with our net earnings.


	THREE MONTHS						NINE MONTHS
	ENDED SEPTEMBER 30						ENDED SEPTEMBER 30
($ MILLIONS)	2015			2014			2015			2014
Net earnings (losses) attributable to equity holders		(4	)		(146	)		75			113

Adjustments
Adjustments on derivatives (pre-tax)		112			60			157			37
NUKEM purchase price inventory recovery		—			(2	)		(3	)		(2	)
Impairment charge		—			196			6			196
Income taxes on adjustments		(30	)		(15	)		(42	)		(10	)
Gain on interest in BPLP (after tax)		—			—			—			(127	)

Adjusted net earnings		78			93			193			207

2015 THIRD QUARTER REPORT 9

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


		THREE MONTHS			NINE MONTHS
($ MILLIONS)		ENDED SEPTEMBER 30			ENDED SEPTEMBER 30
Adjusted net earnings – 2014			93			207
Change in gross profit by segment
(We calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A))
Uranium	Lower sales volume		(30	)		(32	)
	Lower realized prices ($US)		(16	)		(33	)
	Foreign exchange impact on realized prices		59			146
	Higher costs		(35	)		(92	)

	change – uranium		(22	)		(11	)

Fuel services	Higher sales volume		1			3
	Higher (lower) realized prices ($Cdn)		(3	)		17
	Lower (higher) costs		11			(2	)

	change – fuel services		9			18

NUKEM	Gross profit		6			14

	change – NUKEM		6			14

Other changes
Higher administration expenditures			—			(10	)
Lower exploration expenditures			1			2
Lower income tax recovery			(27	)		(45	)
Contract termination fee (SFL)			—			18
Partial arbitration award			—			(28	)
Debenture redemption premium			—			12
Loss on disposal of assets			2			7
Loss on derivatives			(2	)		(46	)
Loss on equity-accounted investments			3			15
Foreign exchange gains			19			41
Other			(4	)		(1	)

Adjusted net earnings – 2015			78			193

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

Quarterly trends


HIGHLIGHTS	2015									2014										2013
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q3			Q2			Q1			Q4		Q3			Q2			Q1		Q4
Revenue		649			565			566			889		587			502			419		977
Net earnings (losses) attributable to equity holders		(4	)		88			(9	)		73		(146	)		127			131		64
$ per common share (basic)		(0.01	)		0.22			(0.02	)		0.18		(0.37	)		0.32			0.33		0.16
$ per common share (diluted)		(0.01	)		0.22			(0.02	)		0.18		(0.37	)		0.32			0.33		0.16
Adjusted net earnings (non-IFRS, see page 9)		78			46			69			205		93			79			36		150
$ per common share (adjusted and diluted)		0.20			0.12			0.18			0.52		0.23			0.20			0.09		0.38
Earnings (losses) from continuing operations		(4	)		88			(10	)		72		(146	)		127			4		28
$ per common share (basic)		(0.01	)		0.22			(0.02	)		0.18		(0.37	)		0.32			0.01		0.07
$ per common share (diluted)		(0.01	)		0.22			(0.02	)		0.18		(0.37	)		0.32			0.01		0.07
Cash provided by (used in) continuing operations (after working capital changes)		(121	)		(65	)		134			236		263			(25	)		7		163

10 CAMECO CORPORATION

Key things to note:

•

our financial results are strongly influenced by the performance of our uranium segment, which accounted for 60% of consolidated revenues in the third quarter of 2015

•

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

•

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

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


HIGHLIGHTS	2015									2014												2013
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
Net earnings (losses) attributable to equity holders		(4	)		88			(9	)		73			(146	)		127			131			64

Adjustments
Adjustments on derivatives (pre-tax)		112			(57	)		101			10			60			(66	)		44			36
NUKEM purchase price inventory recovery		—			—			(3	)		(4	)		(2	)		—			—			(3	)
Impairment charges		—			—			6			172			196			—			—			70
Income taxes on adjustments		(30	)		15			(26	)		(46	)		(15	)		18			(12	)		(17	)
Gain on sale of BPLP (after tax)		—			—			—			—			—			—			(127	)		—

Adjusted net earnings (non-IFRS, see page 9)		78			46			69			205			93			79			36			150

Discontinued operation

Corporate expenses

ADMINISTRATION


	THREE MONTHS						NINE MONTHS
	ENDED SEPTEMBER 30						ENDED SEPTEMBER 30
($ MILLIONS)	2015		2014		CHANGE		2015		2014		CHANGE
Direct administration		38		38		—		122		112		9	%
Stock-based compensation		2		2		—		10		10		—
Total administration		40		40		—		132		122		8	%

Direct administration costs were unchanged compared to the same period last year, and $10 million higher for the first nine months due to slightly higher planned expenditures related to the timing of project work and other costs, as well as costs related to our collaboration agreements.

Stock based compensation in the first nine months was unchanged from 2014.

EXPLORATION

In the third quarter, uranium exploration expenses were $10 million, a decrease of $1 million compared to the third quarter of 2014. Exploration expenses for the first nine months of the year decreased by $2 million compared to 2014, to $33 million, due to a planned reduction in expenditures.

2015 THIRD QUARTER REPORT 11

INCOME TAXES

We recorded an income tax recovery of $35 million in the third quarter of 2015, compared to a recovery of $48 million in the third quarter of 2014.

On an adjusted basis, we recorded an income tax recovery of $5 million this quarter compared to recovery of $32 million in the third quarter of 2014. In 2015, we recorded losses of $115 million in Canada compared to $169 million in 2014, while earnings in foreign jurisdictions decreased to $187 million from $229 million.

In the first nine months of 2015, we recorded an income tax recovery of $85 million compared to a recovery of $99 million in 2014.

On an adjusted basis, we recorded an income tax recovery of $45 million for the first nine months compared to a recovery of $90 million in 2014 due to higher pre-tax adjusted earnings and increased tax expense in foreign jurisdictions in 2015.


	THREE MONTHS						NINE MONTHS
	ENDED SEPTEMBER 30						ENDED SEPTEMBER 30
($ MILLIONS)	2015			2014			2015			2014
Pre-tax adjusted earnings¹
Canada²		(115	)		(169	)		(382	)		(435	)
Foreign		187			229			529			552

Total pre-tax adjusted earnings		72			60			147			117

Adjusted income taxes¹
Canada²		(26	)		(43	)		(86	)		(111	)
Foreign		21			11			41			21

Adjusted income tax recovery		(5	)		(32	)		(45	)		(90	)

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).

TRANSFER PRICING DISPUTES

Transfer pricing is a complex area of tax law, and it is difficult to predict the outcome of cases like ours. However, tax authorities generally test two things:

•

the governance (structure) of the corporate entities involved in the transactions

•

the price at which goods and services are sold by one member of a corporate group to another

12 CAMECO CORPORATION

CRA dispute


	CASH			INTEREST AND		TRANSFER PRICING
YEAR PAID ($ MILLIONS)	TAXES			INSTALMENT PENALTIES		PENALTIES		TOTAL
Prior to 2013		—			13		—		13
2013		1			9		36		46
2014		106			47		—		153
2015		(63	)		1		79		17
Total		44			70		115		229


$ MILLIONS	2003 - 2014		2015		2016 - 2017		2018 - 2023		TOTAL
50% of cash taxes and transfer pricing penalties paid, secured or owing in the period¹
Cash payments		143		35 - 60		155 - 180		0		335 - 360
Potential letters of credit		0		255 - 280		95 - 120		15 - 40		380 - 400
Total paid		143		295 - 320		255 - 280		15 - 40		725 - 750

¹	These amounts do not include interest and instalment penalties, which totalled approximately $70 million to September 30, 2015.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to the Government of Canada, including the $229 million already paid to date.

2015 THIRD QUARTER REPORT 13

IRS dispute

•

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

•

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

We believe that the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

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

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

Assumptions

•

CRA will reassess us for the years 2010 through 2014 using a similar methodology as for the years 2003 through 2009, and the reassessments will be issued on the basis we expect

•

we will be able to apply elective deductions to the extent anticipated

•

we will be able to utilize letters of credit to the extent anticipated

•

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

•

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

•

we will be substantially successful in our dispute with IRS

Material risks that could cause actual results to differ materially

•

the time lag for the reassessments for each year is different than we currently expect

•

cash tax payable increases due to unanticipated adjustments by CRA or IRS not related to transfer pricing

•

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

•

we are unable to effectively eliminate all double taxation

14 CAMECO CORPORATION

FOREIGN EXCHANGE

At September 30, 2015:

•

The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.34 (Cdn), up from $1.00 (US) for $1.25 (Cdn) at June 30, 2015. The exchange rate averaged $1.00 (US) for $1.31 (Cdn) over the quarter.

•

We had foreign currency forward contracts of $1.3 billion (US), €15 million (EUR), and foreign currency options of $230 million (US). The US currency forward contracts had an average exchange rate of $1.00 (US) for $1.19 (Cdn), US currency option contracts had an average exchange rate range of $1.00 (US) for $1.25 to $1.32 (Cdn), and €1.00 for $1.12 (US) for EUR currency contracts.

•

The mark-to-market loss on all foreign exchange contracts was $202 million at September 30, 2015 compared to a $120 million loss at June 30, 2015.

Outlook for 2015

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

See 2015 Financial results by segment on page 19 for details.

2015 FINANCIAL OUTLOOK


	CONSOLIDATED			URANIUM			FUEL SERVICES			NUKEM
Production		—			27.3 million lbs			9 to 10 million kgU			—

Sales volume¹		—			31 to 33 million lbs			Decrease 5% to 10	%		7 to 8 million lbs U₃O₈

Revenue compared to 2014²		Increase 5% to 10	%		Increase 5% to 10	%³		Increase 5% to 10	%		Increase 30% to 35	%

Average unit cost of sales (including D&A)		—			Increase 5% to 10	%⁴		Increase 5% to 10	%		Increase 15% to 20	%

Direct administration costs compared to 2014⁵		Increase 5% to 10	%		—			—			—

Exploration costs compared to 2014		—			Decrease 5% to 1	0%		—			—

Tax rate⁶		Recovery of 25% to 30	%		—			—			—

Capital expenditures		$385 million			—			—			—

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

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

³	Based on a uranium spot price of $36.50 (US) per pound (the Ux spot price as of October 26, 2015), a long-term price indicator of $44.00 (US) per pound (the Ux long-term indicator on October 26, 2015) and an exchange rate of $1.00 (US) for $1.25 (Cdn).

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

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

⁶	Our outlook for the tax rate is based on adjusted net earnings.

2015 THIRD QUARTER REPORT 15

REVENUE AND EARNINGS SENSITIVITY ANALYSIS

For the rest of 2015:

•

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

The following table and graph are not forecasts of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table and graph. They are designed to indicate how the portfolio of long-term contracts we had in place on September 30, 2015 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, 2015 and none of the assumptions we list below change.

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

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)


SPOT PRICES
($US/lb U₃O₈)	$20		$40		$60		$80		$100		$120		$140
2015		45		45		47		48		50		52		53
2016		40		46		57		68		78		88		96
2017		39		46		57		68		78		88		95
2018		40		47		58		69		80		89		97
2019		40		47		59		69		79		87		93

16 CAMECO CORPORATION

LOGO

The table and graph illustrate the mix of long-term contracts in our September 30, 2015 portfolio, and are consistent with our marketing strategy. Both have been updated to reflect deliveries made and contracts entered into up to September 30, 2015.

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 29 million pounds per year, with commitment levels in 2015 through 2018 higher than in 2019

•

excludes sales between our uranium, fuel services and NUKEM segments

Deliveries

•

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

•

we defer a portion of deliveries under existing contracts for 2015

Annual inflation

•

is 2% in the US

Prices

•

the average long-term price indicator is the same as the average spot price for the entire year (a simplified approach for this purpose only). Since 1996, the long-term price indicator has averaged 19% higher than the spot price. This differential has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table and graph will be higher

Liquidity and capital resources

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

We have large, creditworthy customers that continue to need uranium even during weak economic conditions, and we expect the uranium contract portfolio we have built to provide a solid revenue stream for years to come.

We expect to continue investing in maintaining and prudently expanding our production capacity over the next several years. We have a number of alternatives to fund future capital requirements, including using our current cash balances, drawing on our existing credit facilities, entering new credit facilities, using our operating cash flow, and raising additional capital through debt or equity financings. We are always considering our financing options so we can take advantage of favourable market conditions when they arise. However, we expect our cash balances and operating cash flows will meet our anticipated 2015 capital requirements without the need for significant additional funding, assuming we are able to use letters of credit to secure amounts owing to the CRA as outlined in the table on page 13. If we are unable to use letters of credit, we will be required to draw on our existing credit facility.

We have an ongoing transfer pricing dispute with CRA. See page 13 for more information. Until this dispute is resolved, we expect to remit to CRA, 50% of the cash taxes payable and the related interest and penalties. As an alternative to paying cash, we expect to be able to provide security in the form of letters of credit. In the table on page 13, we have provided an estimate of the amount, timing and anticipated form of payment or security for the expected cash taxes and transfer pricing penalties.

2015 THIRD QUARTER REPORT 17

CASH FROM OPERATIONS

Cash from continuing operations was $384 million lower this quarter than in the third quarter of 2014. Contributing to this change was an increase in working capital requirements, partially offset by a decrease in income taxes paid. Working capital required $303 million more in 2015, largely as a result of increases in accounts receivable and inventory and a reduction in accounts payable during the quarter. Not including working capital requirements, our operating cash flows this quarter were lower by $81 million.

Cash from continuing operations was $297 million lower in the first nine months of 2015 than for the same period in 2014 due largely to an increase in inventory, partially offset by a decrease in income taxes paid. Working capital required $310 million more in 2015. Not including working capital requirements, our operating cash flows in the first nine months were higher by $13 million.

FINANCING ACTIVITIES

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $2.4 billion at September 30, 2015, unchanged from June 30, 2015. At September 30, 2015, we had approximately $1.0 billion outstanding in letters of credit. On October 5, 2015, we extended the term of our undrawn $1.25 billion unsecured revolving credit facility that was maturing on November 1, 2018. This credit facility now matures on November 1, 2019.

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

Long-term contractual obligations

Since December 31, 2014, there have been no material changes to our long-term contractual obligations. Please see our annual MD&A for more information.

OFF-BALANCE SHEET ARRANGEMENTS

We had two kinds of off-balance sheet arrangements at September 30, 2015:

•

purchase commitments

•

financial assurances

Purchase commitments

The following table is based on our purchase commitments at September 30, 2015. These commitments include a mix of fixed price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of purchase. We will update this table as required in our MD&A to reflect changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.


			2016 AND		2018 AND		2020 AND
SEPTEMBER 30 ($ MILLIONS)	2015		2017		2019		BEYOND		TOTAL
Purchase commitments¹		258		1,318		387		564		2,527

¹	Denominated in US dollars, converted to Canadian dollars as of September 30, 2015 at the rate of $1.34.

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, 2015, we had commitments of about $2.5 billion for the following:

•

approximately 36 million pounds of U₃O₈ equivalent from 2015 to 2028

•

approximately 4 million kgU as UF₆ in conversion services from 2015 to 2018

•

about 0.6 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-Western supplier

The suppliers do not have the right to terminate agreements other than pursuant to customary events of default provisions.

18 CAMECO CORPORATION

Financial assurances

At September 30, 2015 our financial assurances totaled $1.0 billion, unchanged from June 30, 2015.

BALANCE SHEET


($ MILLIONS)	SEP 30, 2015		DEC 31, 2014		CHANGE
Cash, short-term investments and bank overdraft		63		567		(89	)%
Total debt		1,492		1,491		—
Inventory		1,352		902		50	%

Total cash and short-term investments at September 30, 2015 were $63 million, or 89% lower than at December 31, 2014, primarily due to capital expenditures of $292 million, dividend payments of $119 million, interest payments of $49 million, and cash used in operations of $53 million. Net debt at September 30, 2015 was $1,429 million.

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

Total product inventories increased to $1,352 million, including NUKEM’s inventories ($278 million). Uranium inventories increased as sales were lower than production and purchases in the first nine months of the year and the cost of material purchased during the year was higher than the average cost of inventory at the beginning of the year. In addition, the weakening of the Canadian dollar increased the Canadian carrying value of inventory in our foreign subsidiaries.

Fuel services inventories increased as the cost of material produced during the year was higher than the average cost of inventory at the beginning of the year.

Financial results by segment

Uranium


				THREE MONTHS							NINE MONTHS
				ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
HIGHLIGHTS				2015		2014		CHANGE			2015		2014		CHANGE
Production volume (million lbs)					8.2		5.4		52	%		18.7		15.1		24	%

Sales volume (million lbs)¹					6.9		9.0		(23	)%		21.2		23.3		(9	)%

Average spot price	($	US/lb	)		36.21		31.80		14	%		36.91		31.90		16	%
Average long-term price	($	US/lb	)		44.17		44.33		—			47.06		45.94		2	%
Average realized price	($	US/lb	)		43.61		45.87		(5	)%		44.57		46.14		(3	)%
	($	Cdn/lb	)		56.07		49.83		13	%		55.65		50.35		11	%

Average unit cost of sales (including D&A)	($	Cdn/lb	)		40.16		35.09		14	%		39.13		34.81		12	%

Revenue ($ millions)¹					388		447		(13	)%		1,179		1,171		1	%

Gross profit ($ millions)					110		132		(17	)%		350		362		(3	)%

Gross profit (%)					28		30		(7	)%		30		31		(3	)%

THIRD QUARTER

The 13% decrease in uranium revenues was a result of a 23% decrease in sales volume, partially offset by a 13% increase in the Canadian dollar average realized price.

2015 THIRD QUARTER REPORT 19

The net effect was a $22 million decrease in gross profit for the quarter.

FIRST NINE MONTHS

The net effect was a $12 million decrease in gross profit for the first nine months.


	THREE MONTHS							NINE MONTHS
	ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
($CDN/LB)	2015		2014		CHANGE			2015		2014		CHANGE
Produced
Cash cost		17.56		17.91		(2	)%		22.97		21.19		8	%
Non-cash cost		9.53		7.31		30	%		11.79		10.47		13	%

Total production cost		27.09		25.22		7	%		34.76		31.66		10	%

Quantity produced (million lbs)		8.2		5.4		52	%		18.7		15.1		24	%

Purchased
Cash cost		47.19		30.91		53	%		46.83		37.25		26	%

Quantity purchased (million lbs)		2.7		1.8		50	%		9.3		3.4		174	%

Totals
Produced and purchased costs^{1, 2}		32.07		26.64		20	%		38.77		32.69		19	%

Quantities produced and purchased (million lbs)		10.9		7.2		51	%		28.0		18.5		51	%

¹	This quarter, cash costs of purchased material were $37.78 US per pound compared to $27.98 US per pound in the same period in 2014. In the third quarter the exchange rate on purchases averaged $1.00 (US) for $1.25 (Cdn) compared to $1.00 (US) for $1.10 (Cdn) in the third quarter of 2014.

20 CAMECO CORPORATION

Cash and total cost per pound reconciliation


	THREE MONTHS						NINE MONTHS
	ENDED SEPTEMBER 30						ENDED SEPTEMBER 30
($ MILLIONS)	2015			2014			2015			2014
Cost of product sold		205.5			248.2			660.9			633.8
Add / (subtract)
Royalties		(31.3	)		(21.5	)		(67.0	)		(56.7	)
Standby charges		—			(5.8	)		—			(24.8	)
Other selling costs		(1.9	)		(1.2	)		(7.1	)		(6.7	)
Change in inventories		99.1			(67.3	)		278.1			(99.0	)

Cash operating costs (a)		271.4			152.4			864.9			446.6
Add / (subtract)
Depreciation and amortization		72.2			66.7			168.2			175.9
Change in inventories		6.0			(27.3	)		52.5			(17.7	)

Total operating costs (b)		349.6			191.8			1,085.6			604.8

Uranium produced & purchased (million lbs) (c)		10.9			7.2			28.0			18.5

Cash costs per pound (a ÷ c)		24.90			21.17			30.89			24.14
Total costs per pound (b ÷ c)		32.07			26.64			38.77			32.69

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)


				THREE MONTHS							NINE MONTHS
				ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
HIGHLIGHTS				2015		2014		CHANGE			2015		2014		CHANGE
Production volume (million kgU)					0.6		1.1		(45	)%		6.3		8.9		(29	)%
Sales volume (million kgU)					3.8		3.1		23	%		9.1		8.2		11	%
Average realized price	($	Cdn/kgU	)		22.22		23.11		(4	)%		24.11		22.21		9	%
Average unit cost of sales (including D&A)	($	Cdn/kgU	)		18.75		21.55		(13	)%		19.71		19.46		1	%
Revenue ($ millions)					83		71		17	%		220		182		21	%
Gross profit ($ millions)					13		5		160	%		40		23		74	%
Gross profit (%)					16		7		129	%		18		13		38	%

THIRD QUARTER

2015 THIRD QUARTER REPORT 21

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

FIRST NINE MONTHS

The net effect was a $17 million increase in gross profit.

NUKEM


				THREE MONTHS							NINE MONTHS
				ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
HIGHLIGHTS				2015		2014		CHANGE			2015		2014		CHANGE
Uranium sales (million lbs)¹					2.9		2.5		16	%		6.9		4.7		47	%
Average realized price	($	Cdn/lb	)		52.70		38.52		37	%		46.97		39.72		18	%
Cost of product sold (including D&A)					170		88		93	%		326		171		91	%
Revenue ($ millions)¹					183		97		89	%		361		190		90	%
Gross profit ($ millions)					14		9		56	%		35		19		84	%
Gross profit (%)					8		9		(11	)%		10		10		—

¹	Includes sales and revenue between our uranium, fuel services and NUKEM segments (130,000 pounds in sales and revenue of $6.0 million in Q3, 2015, nil in Q3, 2014; 873,000 pounds in sales and revenue of $19.3 million in the first nine months of 2015, nil in the first nine months of 2014).

THIRD QUARTER

The net effect was a $5 million increase in gross profit.

FIRST NINE MONTHS

The net effect was a $16 million increase in gross profit.

22 CAMECO CORPORATION

Our operations

Uranium – production overview

Production in our uranium segment this quarter was 52% higher than the third quarter of 2014 and 24% higher for the first nine months. See below for more information.

URANIUM PRODUCTION


	THREE MONTHS							NINE MONTHS
	ENDED SEPTEMBER 30							ENDED SEPTEMBER 30
OUR SHARE (MILLION LBS)	2015		2014		CHANGE			2015		2014		CHANGE			2015 PLAN
McArthur River/Key Lake		3.9		3.1		26	%		9.5		9.0		6	%		13.7
Cigar Lake		1.8		—		—			3.3		—		—			5.0
Inkai		1.0		0.8		25	%		2.2		2.2		—			3.0
Rabbit Lake		1.1		0.9		22	%		2.2		2.0		10	%		3.9
Smith Ranch-Highland		0.3		0.5		(40	)%		1.2		1.5		(20	)%		1.4
Crow Butte		0.1		0.1		—			0.3		0.4		(25	)%		0.3
Total		8.2		5.4		52	%		18.7		15.1		24	%		27.3

Uranium 2015 Q3 updates

MCARTHUR RIVER/KEY LAKE

Production update

Production for the quarter was 26% higher compared to the same period last year and 6% higher for the first nine months due to the timing of mill maintenance.

Operations update

CIGAR LAKE

Production update

Rampup schedule

Caution about forward-looking information relating to Cigar Lake

This discussion of our expectations for Cigar Lake, including our plan for 10 million packaged pounds (100%) in 2015, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 2.

2015 THIRD QUARTER REPORT 23

INKAI

Production update

RABBIT LAKE

Production update

Production for the quarter was 22% higher than the same period last year due to the timing of our planned mill maintenance outage. Production for the first nine months was 10% higher from 2014 and the operation remains on track to achieve our planned 2015 production.

Tailings capacity

Our plan for fully utilizing the available tailings capacity at Rabbit Lake requires regulatory approval in 2016 and we have now submitted the required licence application. Recent survey information on the existing level of tailings deposited has indicated there is some additional tailings capacity available. The impact of this information on the mine plan is currently under evaluation.

SMITH RANCH-HIGHLAND AND CROW BUTTE

Production update

At our US operations, as expected, total production was 33% lower for the quarter and 21% lower for the first nine months compared to the same periods in 2014, primarily due to a declining head grade at Crow Butte, and lower levels of planned development at Smith Ranch – Highland.

Fuel services 2015 Q3 updates

PORT HOPE CONVERSION SERVICES

CAMECO FUEL MANUFACTURING INC. (CFM)

Production update

Fuel services produced 0.6 million kgU in the third quarter, 45% lower than the same period last year. Production for the first nine months was 29% lower than last year. Reduced volumes for the quarter and year to date are attributable to the early termination of the SFL contract in 2014. We decreased our production target in 2015 to between 9 million and 10 million kgU, so quarterly production is expected to be lower than comparable periods in 2014.

Qualified persons

MCARTHUR RIVER/KEY LAKE

•

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

CIGAR LAKE

•

Les Yesnik, general manager, Cigar Lake, Cameco

INKAI

•

Darryl Clark, general director, JV Inkai

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, 2015, we carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer (CEO) and chief financial officer (CFO), of the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon that evaluation and as of September 30, 2015, the CEO and CFO concluded that:

•

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

•

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

There has been no change in our internal control over financial reporting during the quarter ended September 30, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

2015 THIRD QUARTER REPORT 25

Exhibit 99.3

LOGO

Cameco Corporation

2015 condensed consolidated interim financial statements

(unaudited)

October 30, 2015

Cameco Corporation

Consolidated statements of earnings


(Unaudited)			Three months ended						Nine months ended
($Cdn thousands, except per share amounts)	Note		Sep 30/15			Sep 30/14			Sep 30/15			Sep 30/14
Revenue from products and services			$	649,050		$	587,136		$	1,779,338		$	1,508,336
Cost of products and services sold				440,822			365,704			1,163,695			906,030
Depreciation and amortization				75,137			78,550			200,415			215,995

Cost of sales				515,959			444,254			1,364,110			1,122,025

Gross profit				133,091			142,882			415,228			386,311
Administration				40,120			40,275			131,792			121,924
Impairment charges		5		—			195,995			5,688			195,995
Exploration				9,681			11,024			32,953			34,763
Research and development				1,571			1,619			4,865			3,312
Loss on sale of assets				2			1,617			446			7,173

Earnings (loss) from operations				81,717			(107,648	)		239,484			23,144
Finance costs		11		(26,040	)		(25,735	)		(76,377	)		(84,973	)
Loss on derivatives		17		(127,382	)		(72,752	)		(237,015	)		(71,273	)
Finance income				868			2,039			4,638			5,278
Share of earnings (loss) from equity-accounted investees				746			(1,929	)		(622	)		(15,431	)
Other income		12		30,617			11,848			58,703			28,419

Loss before income taxes				(39,474	)		(194,177	)		(11,189	)		(114,836	)
Income tax recovery		13		(35,116	)		(47,758	)		(85,027	)		(98,826	)

Net earnings (loss) from continuing operations				(4,358	)		(146,419	)		73,838			(16,010	)
Net earnings from discontinued operation		4		—			—			—			127,243

Net earnings (loss)			$	(4,358	)	$	(146,419	)	$	73,838		$	111,233

Net earnings (loss) attributable to:
Equity holders			$	(3,911	)	$	(146,000	)	$	75,223		$	112,544
Non-controlling interest				(447	)		(419	)		(1,385	)		(1,311	)

Net earnings (loss)			$	(4,358	)	$	(146,419	)	$	73,838		$	111,233

Earnings (loss) per common share attributable to equity holders
Continuing operations				(0.01	)		(0.37	)		0.19			(0.04	)
Discontinued operation				—			—			—			0.32

Total basic earnings (loss) per share		14	$	(0.01	)	$	(0.37	)	$	0.19		$	0.28

Continuing operations				(0.01	)		(0.37	)		0.19			(0.04	)
Discontinued operation				—			—			—			0.32

Total diluted earnings (loss) per share		14	$	(0.01	)	$	(0.37	)	$	0.19		$	0.28

See accompanying notes to condensed consolidated interim financial statements.

2 CAMECO CORPORATION

Cameco Corporation

Consolidated statements of comprehensive income


(Unaudited)			Three months ended						Nine months ended
($Cdn thousands)	Note		Sep 30/15			Sep 30/14			Sep 30/15			Sep 30/14
Net earnings (loss)			$	(4,358	)	$	(146,419	)	$	73,838		$	111,233
Other comprehensive income, net of taxes		13
Items that are or may be reclassified to net earnings:
Exchange differences on translation of foreign operations				49,271			24,086			99,809			55,790
Gains on derivatives designated as cash flow hedges transferred to net earnings - discontinued operation				—			—			—			(300	)
Unrealized gains (losses) on available-for-sale assets				—			49			22			(393	)

Other comprehensive income, net of taxes				49,271			24,135			99,831			55,097

Total comprehensive income (loss)			$	44,913		$	(122,284	)	$	173,669		$	166,330

Comprehensive income (loss) from continuing operations			$	44,913		$	(122,284	)	$	173,669		$	39,387
Comprehensive income from discontinued operation		4		—			—			—			126,943

Total comprehensive income (loss)			$	44,913		$	(122,284	)	$	173,669		$	166,330

Other comprehensive income (loss) attributable to:
Equity holders			$	49,351		$	24,103		$	99,931		$	55,039
Non-controlling interest				(80	)		32			(100	)		58

Other comprehensive income for the period			$	49,271		$	24,135		$	99,831		$	55,097

Total comprehensive income (loss) attributable to:
Equity holders			$	45,440		$	(121,897	)	$	175,154		$	167,583
Non-controlling interest				(527	)		(387	)		(1,485	)		(1,253	)

Total comprehensive income (loss) for the period			$	44,913		$	(122,284	)	$	173,669		$	166,330

See accompanying notes to condensed consolidated interim financial statements.

2015 THIRD QUARTER REPORT 3

Cameco Corporation

Consolidated statements of financial position


(Unaudited)			As at
($Cdn thousands)	Note		Sep 30/15			Dec 31/14
Assets
Current assets
Cash and cash equivalents			$	62,540		$	566,583
Accounts receivable				348,226			455,002
Current tax assets				2,159			3,096
Inventories		6		1,352,398			902,278
Supplies and prepaid expenses				174,032			130,406
Current portion of long-term receivables, investments and other		7		30,229			10,341

Total current assets				1,969,584			2,067,706

Property, plant and equipment				5,393,287			5,291,021
Goodwill and intangible assets				214,601			201,102
Long-term receivables, investments and other		5, 7		459,333			423,280
Investments in equity-accounted investees		5		2,608			3,230
Deferred tax assets				620,879			486,328

Total non-current assets				6,690,708			6,404,961

Total assets			$	8,660,292		$	8,472,667

Liabilities and shareholders’ equity
Current liabilities
Accounts payable and accrued liabilities			$	268,558		$	316,258
Current tax liabilities				29,429			51,719
Dividends payable				39,579			39,579
Current portion of other liabilities		8		258,153			87,883
Current portion of provisions		9		25,939			20,375

Total current liabilities				621,658			515,814

				—
Long-term debt				1,491,968			1,491,198
Other liabilities		8		149,704			172,034
Provisions		9		857,938			825,935
Deferred tax liabilities				31,894			23,882

Total non-current liabilities				2,531,504			2,513,049

				—
Shareholders’ equity
Share capital				1,862,646			1,862,646
Contributed surplus				205,206			196,815
Retained earnings				3,289,588			3,333,099
Other components of equity				151,015			51,084

Total shareholders’ equity attributable to equity holders				5,508,455			5,443,644
Non-controlling interest				(1,325	)		160

Total shareholders’ equity				5,507,130			5,443,804

Total liabilities and shareholders’ equity			$	8,660,292		$	8,472,667

Commitments and contingencies [notes 9, 13]

See accompanying notes to condensed consolidated interim financial statements.

4 CAMECO CORPORATION

Cameco Corporation

Consolidated statements of changes in equity


	Attributable to equity holders
									Foreign			Cash			Available-						Non-
	Share		Contributed			Retained			currency			flow			for-sale						controlling			Total
($Cdn thousands)	capital		surplus			earnings			translation			hedges			assets			Total			interest			equity
Balance at January 1, 2015	$	1,862,646	$	196,815		$	3,333,099		$	51,667		$	—		$	(583	)	$	5,443,644		$	160		$	5,443,804
Net earnings (loss)		—		—			75,223			—			—			—			75,223			(1,385	)		73,838
Other comprehensive income (loss) for the period		—		—			—			99,909			—			22			99,931			(100	)		99,831

Total comprehensive income (loss) for the period		—		—			75,223			99,909			—			22			175,154			(1,485	)		173,669

Share-based compensation		—		12,944			—			—			—			—			12,944			—			12,944
Share options exercised		—		(4,553	)		—			—			—			—			(4,553	)		—			(4,553	)
Dividends		—		—			(118,734	)		—			—			—			(118,734	)		—			(118,734	)

Balance at September 30, 2015	$	1,862,646	$	205,206		$	3,289,588		$	151,576		$	—		$	(561	)	$	5,508,455		$	(1,325	)	$	5,507,130

Balance at January 1, 2014	$	1,854,671	$	186,382		$	3,314,049		$	(7,165	)	$	300		$	28		$	5,348,265		$	1,129		$	5,349,394
Net earnings (loss)		—		—			112,544			—			—			—			112,544			(1,311	)		111,233
Other comprehensive income (loss) for the period		—		—			—			55,732			(300	)		(393	)		55,039			58			55,097

Total comprehensive income (loss) for the period		—		—			112,544			55,732			(300	)		(393	)		167,583			(1,253	)		166,330

Share-based compensation		—		12,310			—			—			—			—			12,310			—			12,310
Share options exercised		7,952		(5,371	)		—			—			—			—			2,581			—			2,581
Dividends		—		—			(118,653	)		—			—			—			(118,653	)		—			(118,653	)
Transactions with owners - contributed equity		—		—			—			—			—			—			—			794			794

Balance at September 30, 2014	$	1,862,623	$	193,321		$	3,307,940		$	48,567		$	—		$	(365	)	$	5,412,086		$	670		$	5,412,756

See accompanying notes to condensed consolidated interim financial statements.

2015 THIRD QUARTER REPORT 5

Cameco Corporation

Consolidated statements of cash flows


(Unaudited)			Three months ended						Nine months ended
($Cdn thousands)	Note		Sep 30/15			Sep 30/14			Sep 30/15			Sep 30/14
Operating activities
Net earnings (loss)			$	(4,358	)	$	(146,419	)	$	73,838		$	111,233
Adjustments for:
Depreciation and amortization				75,137			78,550			200,415			215,995
Deferred charges				4,541			64,173			(14,390	)		53,329
Unrealized loss on derivatives				80,778			63,217			127,038			13,873
Share-based compensation		16		3,803			3,472			12,944			12,310
Loss on sale of assets				2			1,617			446			7,173
Finance costs		11		26,040			25,735			76,377			84,973
Finance income				(868	)		(2,039	)		(4,638	)		(5,278	)
Share of loss (earnings) in equity-accounted investees				(746	)		1,929			622			15,431
Impairment charges		5		—			195,995			5,688			195,995
Other income		12		(30,617	)		(12,013	)		(58,392	)		(18,137	)
Discontinued operation		4		—			—			—			(127,243	)
Income tax recovery		13		(35,116	)		(47,758	)		(85,027	)		(98,826	)
Interest received				483			1,957			3,686			4,154
Income taxes received (paid)				15,329			(12,173	)		(80,870	)		(220,034	)
Other operating items		15		(255,668	)		46,584			(310,568	)		(605	)

Net cash provided by (used in) operations				(121,260	)		262,827			(52,831	)		244,343

Investing activities
Additions to property, plant and equipment				(96,978	)		(127,070	)		(292,072	)		(350,200	)
Decrease (increase) in short-term investments				—			109,417			—			(28,848	)
Decrease in long-term receivables, investments and other				1,574			606			3,512			40
Proceeds from sale of property, plant and equipment				69			1			165			677

Net cash used in investing (continuing operations)				(95,335	)		(17,046	)		(288,395	)		(378,331	)
Net cash provided by investing (discontinued operation)		4		—			—			—			447,096

Net cash provided by (used in) investing				(95,335	)		(17,046	)		(288,395	)		68,765

Financing activities
Increase in debt				—			—			—			496,357
Decrease in debt				(5	)		(309,994	)		(8	)		(351,043	)
Interest paid				(14,173	)		(26,310	)		(48,870	)		(57,624	)
Contributions from non-controlling interest				—			794			—			794
Proceeds from issuance of shares, stock option plan				—			295			—			6,209
Dividends paid				(39,579	)		(39,578	)		(118,734	)		(118,622	)

Net cash used in financing				(53,757	)		(374,793	)		(167,612	)		(23,929	)

Increase (decrease) in cash and cash equivalents net of bank overdraft, during the period				(270,352	)		(129,012	)		(508,838	)		289,179
Exchange rate changes on foreign currency cash balances				2,030			2,238			4,795			1,689
Cash and cash equivalents, net of bank overdraft, beginning of period				330,862			605,551			566,583			187,909

Cash and cash equivalents, net of bank overdraft, end of period			$	62,540		$	478,777		$	62,540		$	478,777

Cash and cash equivalents is comprised of:
Cash										62,540			112,814
Cash equivalents										—			365,963

Cash and cash equivalents									$	62,540		$	478,777

See accompanying notes to condensed consolidated interim financial statements.

6 CAMECO CORPORATION

Cameco Corporation

Notes to condensed consolidated interim financial statements

(Unaudited)

(Cdn$ thousands, except per share amounts and as noted)

1.	Cameco Corporation

Cameco Corporation is incorporated under the Canada Business Corporations Act. The address of its registered office is 2121 11th Street West, Saskatoon, Saskatchewan, S7M 1J3. The condensed consolidated interim financial statements as at and for the period ended September 30, 2015 comprise Cameco Corporation and its subsidiaries (collectively, the Company or Cameco) and the Company’s interests in associates and joint arrangements. The Company is primarily engaged in the exploration for and the development, mining, refining, conversion, fabrication and trading of uranium for sale as fuel for generating electricity in nuclear power reactors in Canada and other countries.

2.	Significant accounting policies

A.	Statement of compliance

These condensed consolidated interim financial statements have been prepared in accordance with IAS 34 Interim Financial Reporting. The condensed consolidated interim financial statements do not include all of the information required for full annual financial statements and should be read in conjunction with Cameco’s annual consolidated financial statements as at and for the year ended December 31, 2014.

These condensed consolidated interim financial statements were authorized for issuance by the Company’s board of directors on October 30, 2015.

B.	Basis of presentation

These condensed consolidated interim financial statements are presented in Canadian dollars, which is the Company’s functional currency. All financial information is presented in Canadian dollars, unless otherwise noted. Amounts presented in tabular format have been rounded to the nearest thousand except per share amounts and where otherwise noted.

The condensed consolidated interim financial statements have been prepared on the historical cost basis except for the following material items which are measured on an alternative basis at each reporting date:


Derivative financial instruments at fair value through profit and loss		Fair value
Non-derivative financial instruments at fair value through profit and loss		Fair value
Available-for-sale financial assets		Fair value
Liabilities for cash-settled share-based payment arrangements		Fair value
Net defined benefit liability		Fair value of plan assets less the present value of the defined benefit obligation

The preparation of the condensed consolidated interim financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, revenue and expenses. Actual results may vary from these estimates.

In preparing these condensed consolidated interim financial statements, the significant judgments made by management in applying the Company’s accounting policies and key sources of estimation uncertainty were the same as those that applied to the consolidated financial statements as at and for the year ended December 31, 2014.

2015 THIRD QUARTER REPORT 7

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. The areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed in note 5 of the December 31, 2014 consolidated financial statements.

3.	Accounting standards

New standards and interpretations not yet adopted

A number of new standards and amendments to existing standards are not yet effective for the period ended September 30, 2015 and have not been applied in preparing these condensed consolidated interim financial statements. The following standards and amendments to existing standards have been published and are mandatory for Cameco’s accounting periods beginning on or after January 1, 2016, unless otherwise noted. Cameco does not intend to early adopt any of the following amendments to existing standards and does not expect the amendments to have a material impact on the financial statements, unless otherwise noted.

i.	Property, plant and equipment and intangible assets

In May 2014, the IASB issued amendments to IAS 16, Property, Plant and Equipment and IAS 38, Intangible Assets. 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.

ii.

Joint arrangements

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

iii.

Sale or contribution of assets

In September 2014, the IASB issued amendments to IFRS 10, Consolidated Financial Statements and IAS 28, Investments in Associates and Joint Ventures. 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.

iv.

Noncurrent assets held for sale and discontinued operations

In September 2014, the IASB issued amendments to IFRS 5, Non-Current Assets Held for Sale and Discontinued Operations (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 to IFRS 5 clarify the application of IFRS 5 when changing from one of these disposal methods to the other.

v.	Financial instruments disclosures

In September 2014, the IASB issued amendments to IFRS 7, Financial Instruments: Disclosures (IFRS 7). The amendments in IFRS 7 are to be applied retrospectively, with earlier application permitted. The amendments to IFRS 7 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.

vi.

Interim financial reporting

In September 2014, the IASB issued amendments to IAS 34, Interim Financial Reporting (IAS 34). The amendments to IAS 34 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.

8 CAMECO CORPORATION

vii.

Revenue

In May 2014, the IASB issued IFRS 15, Revenue from Contracts with Customers (IFRS 15). IFRS 15 is effective for periods beginning on or after January 1, 2018 and is to be applied retrospectively. IFRS 15 clarifies the principles for recognizing revenue from contracts with customers. The extent of the impact of adoption of IFRS 15 has not yet been determined.

viii.

Financial instruments

In July 2014, the IASB issued IFRS 9, Financial Instruments (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. Cameco does not intend to early adopt IFRS 9. The extent of the impact of adoption of IFRS 9 has not yet been determined.

4.	Discontinued operation

On March 27, 2014, Cameco completed the sale of its 31.6% limited partnership interest in Bruce Power L.P. (BPLP) which operates the four Bruce B nuclear reactors in Ontario. The aggregate sale price for Cameco’s interest in BPLP and certain related entities was $450,000,000. The sale was accounted for effective January 1, 2014. Cameco received net proceeds of approximately $447,096,000 and realized an after tax gain of $127,243,000 on this divestiture. As a result of the transaction, Cameco presented the results of BPLP as a discontinued operation and revised its statement of earnings, statement of comprehensive income and statement of cash flows to reflect this change in presentation.

5.	Impairment

A.	GE-Hitachi Global Laser Enrichment LLC (GLE)

During the third quarter of 2014, a decision was made by the majority partner of GLE to significantly reduce funding of the project. As a result, Cameco recognized an impairment charge of $183,615,000, which represented the full amount of Cameco’s investment. Contributions to the project are being reflected in net earnings.

B.	GoviEx Uranium

In 2014, GoviEx Uranium (GoviEx) became listed on the Canadian Securities Exchange. With the availability of a quoted market price, Cameco determined that there was a significant decline in the fair value of its investment in GoviEx and as a result an impairment charge was recorded. For the quarter ended September 30, 2015, no impairment charge was recorded (2014 - $12,380,000). For the nine months ended September 30, 2015, Cameco recorded an impairment charge of $5,688,000 (2014 - $12,380,000).

2015 THIRD QUARTER REPORT 9

6.	Inventories


	Sep 30/15		Dec 31/14
Uranium
Concentrate	$	885,967	$	500,342
Broken ore		42,642		21,289

		928,609		521,631
NUKEM		277,517		251,942
Fuel services		146,272		128,705

Total	$	1,352,398	$	902,278

In the second quarter of 2015, commercial production was achieved at Cameco’s Cigar Lake operation. Effective May 1, 2015, we commenced charging all production costs, including depreciation, to inventory and subsequently recognizing in cost of sales as the product is sold.

Cameco expensed $484,700,000 of inventory as cost of sales during the third quarter of 2015 (2014 - $409,700,000). For the nine months ended September 30, 2015, Cameco expensed $1,298,400,000 of inventory as cost of sales (2014 - $1,011,900,000).

NUKEM enters into financing arrangements where future receivables arising from certain sales contracts are sold to financial institutions in exchange for cash. These arrangements require NUKEM to satisfy its delivery obligations under the sales contracts, which are recognized as deferred sales (note 8). In addition, NUKEM is required to pledge the underlying inventory as security against these performance obligations. As of September 30, 2015, NUKEM had $94,789,000 ($70,770,000 (US)) of inventory pledged as security under financing arrangements (December 31, 2014 - $94,378,000 ($81,353,000 (US))).

7.	Long-term receivables, investments and other


	Sep 30/15			Dec 31/14
Investments in equity securities [note 17]	$	938		$	6,601
Derivatives [note 17]		11,616			3,889
Advances receivable from JV Inkai LLP [note 19]		100,925			91,672
Investment tax credits		93,925			90,658
Amounts receivable related to tax dispute [note 13]		230,253			211,604
Other		51,905			29,197

		489,562			433,621
Less current portion		(30,229	)		(10,341	)

Net	$	459,333		$	423,280

10 CAMECO CORPORATION

8.	Other liabilities


	Sep 30/15			Dec 31/14
Deferred sales	$	129,120		$	123,298
Derivatives [note 17]		203,048			67,916
Accrued pension and post-retirement benefit liability		67,850			61,670
Other		7,839			7,033

		407,857			259,917
Less current portion		(258,153	)		(87,883	)

Net	$	149,704		$	172,034

Deferred sales includes $107,180,000 ($80,021,000 (US)) of performance obligations relating to financing arrangements entered into by NUKEM (December 31, 2014 - $107,076,000 ($92,299,000 (US))) (note 6).

9.	Provisions


	Reclamation			Waste disposal			Total
Beginning of year	$	828,015		$	18,295		$	846,310
Changes in estimates and discount rates		(13,657	)		398			(13,259	)
Provisions used during the period		(7,363	)		(17	)		(7,380	)
Unwinding of discount		15,480			247			15,727
Impact of foreign exchange		42,479			—			42,479

End of period	$	864,954		$	18,923		$	883,877

Current		23,146			2,793			25,939
Non-current		841,808			16,130			857,938

	$	864,954		$	18,923		$	883,877

10.

Share capital

At September 30, 2015, there were 395,792,522 common shares outstanding. Options in respect of 8,615,166 shares are outstanding under the stock option plan and are exercisable up to 2023. For the quarter ended September 30, 2015, there were no options that were exercised resulting in the issuance of shares (2014 - 14,700). For the nine months ended September 30, 2015, there were no options exercised that resulted in the issuance of shares (2014 - 314,292).

11.

Finance costs


	Three months ended				Nine months ended
	Sep 30/15		Sep 30/14		Sep 30/15		Sep 30/14
Interest on long-term debt	$	18,838	$	18,010	$	56,096	$	49,866
Unwinding of discount on provisions		5,628		5,176		15,727		15,240
Loss on redemption of Series C debentures		—		—		—		12,135
Other charges		1,523		1,591		4,485		4,546
Interest on short-term debt		51		958		69		3,186

Total	$	26,040	$	25,735	$	76,377	$	84,973

2015 THIRD QUARTER REPORT 11

12.

Other income


	Three months ended					Nine months ended
	Sep 30/15		Sep 30/14			Sep 30/15		Sep 30/14
Foreign exchange gains	$	30,617	$	12,070		$	58,392	$	17,714
Contract settlement		—		—			—		28,481
Contract termination fee		—		—			—		(18,304	)
Other		—		(222	)		311		528

Total	$	30,617	$	11,848		$	58,703	$	28,419

In the first quarter of 2014, Cameco recorded an early termination fee of $18,304,000, incurred as a result of the cancellation of our toll conversion agreement with Springfields Fuels Ltd., which was to expire in 2016.

During the second quarter of 2014, Cameco recorded a gain with respect to a long-term supply contract with one of its utility customers. The $28,481,000 reflected as income from contract settlement related to deliveries that the customer refused to take in 2012 and 2013.

13.

Income taxes


	Three months ended						Nine months ended
	Sep 30/15			Sep 30/14			Sep 30/15			Sep 30/14
Earnings (loss) from continuing operations before income taxes
Canada	$	(226,999	)	$	(241,077	)	$	(544,264	)	$	(483,191	)
Foreign		187,525			46,900			533,075			368,355

	$	(39,474	)	$	(194,177	)	$	(11,189	)	$	(114,836	)

Current income taxes (recovery)
Canada	$	3,359		$	4,918		$	4,582		$	(1,550	)
Foreign		10,536			18,115			31,801			37,503

	$	13,895		$	23,033		$	36,383		$	35,953
Deferred income taxes (recovery)
Canada	$	(59,535	)	$	(64,528	)	$	(131,879	)	$	(118,714	)
Foreign		10,524			(6,263	)		10,469			(16,065	)

	$	(49,011	)	$	(70,791	)	$	(121,410	)	$	(134,779	)

Income tax recovery	$	(35,116	)	$	(47,758	)	$	(85,027	)	$	(98,826	)

Cameco has recorded $620,879,000 of deferred tax assets (December 31, 2014 - 486,328,000). Based on projections of future income, realization of these deferred tax assets is probable and consequently a deferred tax asset has been recorded.

Canada

In 2008, as part of the ongoing annual audits of Cameco’s Canadian tax returns, Canada Revenue Agency (CRA) disputed the transfer pricing structure and methodology used by Cameco and its wholly owned Swiss subsidiary, Cameco Europe Ltd., in respect of sale and purchase agreements for uranium products. From December 2008 to date, CRA issued notices of reassessment for the taxation years 2003 through 2009, which in aggregate have increased Cameco’s income for Canadian tax purposes by approximately $2,795,000,000. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229,300,000. Cameco believes it is likely that CRA will reassess Cameco’s tax returns for subsequent years on a similar basis and that these will require Cameco to make future remittances on receipt of the reassessments.

12 CAMECO CORPORATION

Using the methodology we believe that CRA will continue to apply and including the $2,795,000,000 already reassessed, we expect to receive notices of reassessment for a total of approximately $6,600,000,000 for the years 2003 through 2014, which would increase Cameco’s income for Canadian tax purposes and result in a related tax expense of approximately $1,900,000,000. In addition to penalties already imposed, CRA may continue to apply penalties to taxation years subsequent to 2009. As a result, we estimate that cash taxes and transfer pricing penalties would be between $1,450,000,000 and $1,500,000,000. In addition, we estimate there would be interest and instalment penalties applied that would be material to Cameco. While in dispute, we would be responsible for remitting 50% of the cash taxes and transfer pricing penalties (between $725,000,000 and $750,000,000), plus related interest and instalment penalties assessed, which would be material to Cameco. As an alternative to paying cash, we expect to be able to provide security in the form of letters of credit to satisfy our requirements.

Under Canadian federal and provincial tax rules, 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. Recently, the CRA proposed to disallow the use of any loss carry-backs to be applied to any transfer pricing adjustment, starting with the 2008 tax year. In light of our view of the likely outcome of the case, we expect to recover the amounts remitted to CRA, including cash taxes, interest and penalties totalling $230,253,000 already paid as at September 30, 2015 (December 31, 2014 - $211,604,000) (note 7).

The case on the 2003, 2005 and 2006 reassessments is expected to go to trial in the third quarter of 2016. If this timing is adhered to, we expect to receive a Tax Court decision within six to 18 months after the trial is complete.

Having regard to advice from its external advisors, Cameco’s opinion is that CRA’s position is incorrect and Cameco is contesting CRA’s position and expects to recover any amounts remitted as a result of the reassessments. However, to reflect the uncertainties of CRA’s appeals process and litigation, Cameco has recorded a cumulative tax provision related to this matter for the years 2003 through the current period in the amount of $92,000,000. While the resolution of this matter may result in liabilities that are higher or lower than the reserve, management believes that the ultimate resolution will not be material to Cameco’s financial position, results of operations or liquidity in the year(s) of resolution. Resolution of this matter as stipulated by CRA would be material to Cameco’s financial position, results of operations or liquidity in the year(s) of resolution and other unfavourable outcomes for the years 2003 to date could be material to Cameco’s financial position, results of operations and cash flows in the year(s) of resolution.

Further to Cameco’s decision to contest CRA’s reassessments, Cameco is pursuing its appeal rights under Canadian federal and provincial tax rules.

United States

In February 2015, one of Cameco’s subsidiaries received a Revenue Agent’s Report (RAR) from the Internal Revenue Service (IRS) pertaining to the 2009 taxation year. The RAR lists the IRS’ proposed adjustments to taxable income and calculates tax and penalties owing based on the proposed adjustments.

The proposed adjustments reflected in the RAR are focused on transfer pricing in respect of certain intercompany transactions within our corporate structure. The IRS asserts that a portion of the non-US income reported under our corporate structure and taxed outside the US should be recognized and taxed in the US. Having regard to advice from its external advisors, management believes that the conclusions of the IRS in the RAR are incorrect and is contesting them in an administrative appeal of the proposed adjustments. No cash payments are required while pursuing an administrative appeal. Management believes that the ultimate resolution of this matter will not be material to our financial position, results of operations or liquidity in the year(s) of resolution.

2015 THIRD QUARTER REPORT 13

Other comprehensive income

Other comprehensive income included on the consolidated statements of comprehensive income and the consolidated statements of changes in equity is presented net of income taxes. The following income tax amounts are included in each component of other comprehensive income:

For the three months ended September 30, 2015


			Income tax
	Before tax		recovery		Net of tax
Exchange differences on translation of foreign operations	$	49,271	$	—	$	49,271

	$	49,271	$	—	$	49,271

For the three months ended September 30, 2014


			Income tax
	Before tax		expense			Net of tax
Exchange differences on translation of foreign operations	$	24,086	$	—		$	24,086
Unrealized gains on available-for-sale assets		57		(8	)		49

	$	24,143	$	(8	)	$	24,135

For the nine months ended September 30, 2015


			Income tax
	Before tax		expense			Net of tax
Exchange differences on translation of foreign operations	$	99,809	$	—		$	99,809
Unrealized gains on available-for-sale assets		25		(3	)		22

	$	99,834	$	(3	)	$	99,831

For the nine months ended September 30, 2014


				Income tax
	Before tax			recovery		Net of tax
Exchange differences on translation of foreign operations	$	55,790		$	—	$	55,790
Unrealized losses on available-for-sale assets		(454	)		61		(393	)
Gains on derivatives designated as cash flow hedges transferred to net earnings - discontinued operation		(400	)		100		(300	)

	$	54,936		$	161	$	55,097

14 CAMECO CORPORATION

14.

Per share amounts

Per share amounts have been calculated based on the weighted average number of common shares outstanding during the period. The weighted average number of paid shares outstanding in 2015 was 395,792,522 (2014 - 395,722,618).


	Three months ended						Nine months ended
	Sep 30/15			Sep 30/14			Sep 30/15		Sep 30/14
Basic earnings (loss) per share computation
Net earnings (loss) attributable to equity holders	$	(3,911	)	$	(146,000	)	$	75,223	$	112,544
Weighted average common shares outstanding		395,793			395,787			395,793		395,723

Basic earnings (loss) per common share	$	(0.01	)	$	(0.37	)	$	0.19	$	0.28

Diluted earnings (loss) per share computation
Net earnings (loss) attributable to equity holders	$	(3,911	)	$	(146,000	)	$	75,223	$	112,544
Weighted average common shares outstanding		395,793			395,787			395,793		395,723
Dilutive effect of stock options		—			79			—		353

Weighted average common shares outstanding, assuming dilution		395,793			395,866			395,793		396,076

Diluted earnings (loss) per common share	$	(0.01	)	$	(0.37	)	$	0.19	$	0.28

15.

Statements of cash flows


	Three months ended						Nine months ended
	Sep 30/15			Sep 30/14			Sep 30/15			Sep 30/14
Changes in non-cash working capital:
Accounts receivable	$	(187,702	)	$	(59,678	)	$	110,070		$	99,247
Inventories		(27,521	)		52,016			(312,569	)		(16,120	)
Supplies and prepaid expenses		(17,489	)		(4,832	)		(40,684	)		45,344
Accounts payable and accrued liabilities		(14,202	)		51,538			(64,382	)		(111,759	)
Reclamation payments		(3,303	)		(4,986	)		(7,380	)		(9,184	)
Other		(5,451	)		12,526			4,377			(8,133	)

Other operating items	$	(255,668	)	$	46,584		$	(310,568	)	$	(605	)

16.

Share-based compensation plans

A.	Stock option plan

The Company has established a stock option plan under which options to purchase common shares may be granted to employees of Cameco. Options granted under the stock option plan have an exercise price of not less than the closing price quoted on the Toronto Stock Exchange (TSX) for the common shares of Cameco on the trading day prior to the date on which the option is granted. The options carry vesting periods of one to three years, and expire eight years from the date granted.

The aggregate number of common shares that may be issued pursuant to the Cameco stock option plan shall not exceed 43,017,198 of which 27,870,079 shares have been issued.

2015 THIRD QUARTER REPORT 15

B.	Executive performance share unit (PSU)

The Company has established a PSU plan whereby it provides each plan participant an annual grant of PSUs in an amount determined by the board. Each PSU represents one phantom common share that entitles the participant to a payment of one Cameco common share purchased on the open market or cash, at the board’s discretion, at the end of each three-year period if certain performance and vesting criteria have been met. The final value of the PSUs will be based on the value of Cameco common shares at the end of the three-year period and the number of PSUs that ultimately vest. Vesting of PSUs is based on Cameco’s performance for total shareholder return, average realized selling price and uranium production over the three year period and whether the participating executive remains employed by Cameco. As of September 30, 2015, the total number of PSUs held by the participants, after adjusting for forfeitures on retirement, was 791,071 (December 31, 2014 - 620,654).

C.	Restricted share unit (RSU)

The Company has established an RSU plan whereby it provides each plan participant an annual grant of RSUs in an amount determined by the board. Each RSU represents one phantom common share that entitles the participant to a payment of one Cameco common share purchased on the open market, or cash, at the board’s discretion. The RSUs carry vesting periods of one to three years, and the final value of the units will be based on the value of Cameco common shares at the end of the vesting periods. As of September 30, 2015, the total number of RSUs held by the participants was 479,320 (December 31, 2014 - 246,394).

Cameco records compensation expense under its equity-settled plans with an offsetting credit to contributed surplus, to reflect the estimated fair value of units granted to employees. During the period, the Company recognized the following expenses under these plans:


	Three months ended				Nine months ended
	Sep 30/15		Sep 30/14		Sep 30/15		Sep 30/14
Stock option plan	$	949	$	1,283	$	4,625	$	6,443
Performance share unit plan		1,624		1,421		4,949		3,778
Restricted share unit plan		1,230		768		3,370		2,089

	$	3,803	$	3,472	$	12,944	$	12,310

Fair value measurement of equity-settled plans

The fair value of the units granted through the PSU plan was determined based on Monte Carlo simulation and the fair value of options granted under the stock option plan was measured based on the Black-Scholes option-pricing model. The fair value of RSUs granted was determined based on their intrinsic value on the date of grant. Expected volatility was estimated by considering historic average share price volatility.

16 CAMECO CORPORATION

The inputs used in the measurement of the fair values at grant date of the equity-settled share-based payment plans were as follows:


	Stock
	option plan			PSU			RSU
Number of options granted		965,823			336,602			298,662
Average strike price	$	19.30			—		$	18.89
Expected dividend	$	0.40			—			—
Expected volatility		32	%		29	%		—
Risk-free interest rate		0.7	%		0.5	%		—
Expected life of option		4.5 years			3 years			—
Expected forfeitures		7	%		5	%		5	%
Weighted average grant date fair values	$	4.30		$	18.88		$	18.89

In addition to these inputs, other features of the PSU grant were incorporated into the measurement of fair value. The market condition based on total shareholder return was incorporated by utilizing a Monte Carlo simulation. The non-market criteria relating to realized selling prices and production targets have been incorporated into the valuation at grant date by reviewing prior history and corporate budgets.

17.

Financial instruments and related risk management

A.	Fair value hierarchy

The fair value of an asset or liability is generally estimated as the amount that would be received on sale of an asset, or paid to transfer a liability in an orderly transaction between market participants at the reporting date. Fair values of assets and liabilities traded in an active market are determined by reference to last quoted prices, in the principal market for the asset or liability. In the absence of an active market for an asset or liability, fair values are determined based on market quotes for assets or liabilities with similar characteristics and risk profiles, or through other valuation techniques. Fair values determined using valuation techniques require the use of inputs, which are obtained from external, readily observable market data when available. In some circumstances, inputs that are not based on observable data must be used. In these cases, the estimated fair values may be adjusted in order to account for valuation uncertainty, or to reflect the assumptions that market participants would use in pricing the asset or liability.

All fair value measurements are categorized into one of three hierarchy levels, described below, for disclosure purposes. Each level is based on the transparency of the inputs used to measure the fair values of assets and liabilities:

Level 1 – Values based on unadjusted quoted prices in active markets that are accessible at the reporting date for identical assets or liabilities.

Level 2 – Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

Level 3 – Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

When the inputs used to measure fair value fall within more than one level of the hierarchy, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety.

2015 THIRD QUARTER REPORT 17

The following tables summarize the carrying amounts and fair values of Cameco’s financial instruments that are measured at fair value, including their levels in the fair value hierarchy:

As at September 30, 2015


				Fair value
	Carrying value			Level 1		Level 2			Total
Derivative assets [note 7]
Foreign currency contracts	$	1,110		$	—	$	1,110		$	1,110
Interest rate contracts		10,506			—		10,506			10,506
Investments in equity securities [note 7]		938			938		—			938
Derivative liabilities [note 8]
Foreign currency contracts		(202,984	)		—		(202,984	)		(202,984	)
Other		(64	)		—		(64	)		(64	)

Net	$	(190,494	)	$	938	$	(191,432	)	$	(190,494	)

As at December 31, 2014


				Fair value
	Carrying value			Level 1		Level 2			Total
Derivative assets [note 7]
Foreign currency contracts	$	911		$	—	$	911		$	911
Interest rate contracts		2,978			—		2,978			2,978
Investments in equity securities [note 7]		6,601			6,601		—			6,601
Derivative liabilities [note 8]
Foreign currency contracts		(67,916	)		—		(67,916	)		(67,916	)

Net	$	(57,426	)	$	6,601	$	(64,027	)	$	(57,426	)

The preceding tables exclude fair value information for financial instruments whose carrying amounts are a reasonable approximation of fair value.

There were no transfers between level 1 and level 2 during the period. Cameco does not have any financial instruments that are classified as level 3 as of the reporting date.

B.	Financial instruments measured at fair value

Cameco measures its short-term investments, derivative financial instruments and material investments in equity securities at fair value. Short-term investments and investments in publicly held equity securities are classified as a recurring level 1 fair value measurement and derivative financial instruments are classified as a recurring level 2 fair value measurement.

Short-term investments represent available-for-sale money market instruments. The fair value of these instruments is determined using quoted market yields as of the reporting date. The fair value of investments in equity securities is determined using quoted share prices observed in the principal market for the securities as of the reporting date.

Foreign currency derivatives consist of foreign currency forward contracts, options and swaps. The fair value of foreign currency options is measured based on the Black Scholes option-pricing model. The fair value of foreign currency forward contracts and swaps is measured using a market approach, based on the difference between contracted foreign exchange rates and quoted forward exchange rates as of the reporting date.

18 CAMECO CORPORATION

Interest rate derivatives consist of interest rate swap contracts and interest rate caps. The fair value of interest rate swaps is determined by discounting expected future cash flows from the contracts. The future cash flows are determined by measuring the difference between fixed interest payments to be received and floating interest payments to be made to the counterparty based on Canada Dealer Offer Rate forward interest rate curves. The fair value of interest rate caps is determined based on broker quotes observed in active markets at the reporting date.

Where applicable, the fair value of the derivatives reflects the credit risk of the instrument and includes adjustments to take into account the credit risk of the Company and counterparty. These adjustments are based on credit ratings and yield curves observed in active markets at the reporting date.

C.	Financial instruments not measured at fair value

The carrying value of Cameco’s cash and cash equivalents, receivables, payables and accrued liabilities is assumed to approximate the fair value as a result of the short-term nature of the instruments. The carrying value of Cameco’s long-term debt (debentures) is assumed to approximate the fair value as a result of the variable interest rate associated with the instruments or the fixed interest rate of the instruments being similar to market rates.

D.	Derivatives

The following table summarizes the fair value of derivatives and classification on the consolidated statements of financial position:


	Sep 30/15			Dec 31/14
Non-hedge derivatives:
Foreign currency contracts	$	(201,874	)	$	(67,005	)
Interest rate contracts		10,506			2,978
Other		(64	)		—

Net	$	(191,432	)	$	(64,027	)

Classification:
Current portion of long-term receivables, investments and other [note 7]	$	4,523		$	500
Long-term receivables, investments and other [note 7]		7,093			3,389
Current portion of other liabilities [note 8]		(188,886	)		(53,873	)
Other liabilities [note 8]		(14,162	)		(14,043	)

Net	$	(191,432	)	$	(64,027	)

The following table summarizes the different components of the loss on derivatives included in net earnings (loss):


	Three months ended						Nine months ended
	Sep 30/15			Sep 30/14			Sep 30/15			Sep 30/14
Non-hedge derivatives
Foreign currency contracts	$	(130,390	)	$	(72,223	)	$	(248,324	)	$	(72,209	)
Interest rate contracts		2,715			(529	)		10,430			920
Other		293			—			879			16

Net	$	(127,382	)	$	(72,752	)	$	(237,015	)	$	(71,273	)

2015 THIRD QUARTER REPORT 19

18.

Segmented information

Cameco has three reportable segments: uranium, fuel services and NUKEM. The uranium segment involves the exploration for, mining, milling, purchase and sale of uranium concentrate. The fuel services segment involves the refining, conversion and fabrication of uranium concentrate and the purchase and sale of conversion services. The NUKEM segment acts as a market intermediary between uranium producers and nuclear-electric utilities.

Cameco’s reportable segments are strategic business units with different products, processes and marketing strategies.

Accounting policies used in each segment are consistent with the policies outlined in the summary of significant accounting policies. Segment revenues, expenses and results include transactions between segments incurred in the ordinary course of business. These transactions are priced on an arm’s length basis, are eliminated on consolidation and are reflected in the “other” column.

20 CAMECO CORPORATION

Business segments

For the three months ended September 30, 2015


	Uranium			Fuel services		NUKEM			Other			Total
Revenue	$	387,661		$	83,479	$	183,381		$	(5,471	)	$	649,050
Expenses
Cost of products and services sold		205,487			62,004		179,251			(5,920	)		440,822
Depreciation and amortization		72,155			8,432		(9,537	)		4,087			75,137

Cost of sales		277,642			70,436		169,714			(1,833	)		515,959

Gross profit (loss)		110,019			13,043		13,667			(3,638	)		133,091
Administration		—			—		4,294			35,826			40,120
Exploration		9,681			—		—			—			9,681
Research and development		—			—		—			1,571			1,571
Loss on sale of assets		2			—		—			—			2
Finance costs		—			—		1,128			24,912			26,040
Loss (gain) on derivatives		—			—		(461	)		127,843			127,382
Finance income		—			—		—			(868	)		(868	)
Share of earnings from equity-accounted investees		(746	)		—		—			—			(746	)
Other expense (income)		—			—		77			(30,694	)		(30,617	)

Earnings (loss) before income taxes		101,082			13,043		8,629			(162,228	)		(39,474	)
Income tax recovery													(35,116	)

Net loss												$	(4,358	)

For the three months ended September 30, 2014


	Uranium		Fuel services			NUKEM			Other			Total
Revenue	$	447,193	$	71,081		$	96,687		$	(27,825	)	$	587,136
Expenses
Cost of products and services sold		248,206		59,171			86,499			(28,172	)		365,704
Depreciation and amortization		66,656		7,130			846			3,918			78,550

Cost of sales		314,862		66,301			87,345			(24,254	)		444,254

Gross profit (loss)		132,331		4,780			9,342			(3,571	)		142,882
Administration		—		—			3,954			36,321			40,275
Impairment charges		12,380		183,615			—			—			195,995
Exploration		11,024		—			—			—			11,024
Research and development		—		—			—			1,619			1,619
Loss on sale of assets		1,617		—			—			—			1,617
Finance costs		—		—			934			24,801			25,735
Loss on derivatives		—		—			24			72,728			72,752
Finance income		—		—			(1	)		(2,038	)		(2,039	)
Share of loss from equity-accounted investees		1,929		—			—			—			1,929
Other expense (income)		222		—			818			(12,888	)		(11,848	)

Earnings (loss) before income taxes		105,159		(178,835	)		3,613			(124,114	)		(194,177	)
Income tax recovery													(47,758	)

Net loss												$	(146,419	)

2015 THIRD QUARTER REPORT 21

For the nine months ended September 30, 2015


	Uranium			Fuel services		NUKEM			Other			Total
Revenue	$	1,179,157		$	219,711	$	361,319		$	19,151		$	1,779,338
Expenses
Cost of products and services sold		660,934			158,305		327,455			17,001			1,163,695
Depreciation and amortization		168,209			21,279		(1,514	)		12,441			200,415

Cost of sales		829,143			179,584		325,941			29,442			1,364,110

Gross profit (loss)		350,014			40,127		35,378			(10,291	)		415,228
Administration		—			—		11,379			120,413			131,792
Impairment charge		5,688			—		—			—			5,688
Exploration		32,953			—		—			—			32,953
Research and development		—			—		—			4,865			4,865
Loss on sale of assets		415			28		3			—			446
Finance costs		—			—		3,432			72,945			76,377
Loss (gain) on derivatives		—			—		(1,229	)		238,244			237,015
Finance income		—			—		(2	)		(4,636	)		(4,638	)
Share of loss from equity-accounted investees		622			—		—			—			622
Other expense (income)		(312	)		—		335			(58,726	)		(58,703	)

Earnings (loss) before income taxes		310,648			40,099		21,460			(383,396	)		(11,189	)
Income tax recovery													(85,027	)

Net earnings												$	73,838

For the nine months ended September 30, 2014


	Uranium			Fuel services			NUKEM			Other			Total
Revenue	$	1,171,172		$	181,530		$	190,310		$	(34,676	)	$	1,508,336
Expenses
Cost of products and services sold		633,766			141,343			167,072			(36,151	)		906,030
Depreciation and amortization		175,893			17,643			4,361			18,098			215,995

Cost of sales		809,659			158,986			171,433			(18,053	)		1,122,025

Gross profit (loss)		361,513			22,544			18,877			(16,623	)		386,311
Administration		—			—			10,368			111,556			121,924
Impairment charges		12,380			183,615			—			—			195,995
Exploration		34,763			—			—			—			34,763
Research and development		—			—			—			3,312			3,312
Loss on sale of assets		7,173			—			—			—			7,173
Finance costs		—			—			3,024			81,949			84,973
Loss on derivatives		—			—			1,719			69,554			71,273
Finance income		—			—			(3	)		(5,275	)		(5,278	)
Share of loss from equity-accounted investees		2,164			13,267			—			—			15,431
Other expense (income)		(28,740	)		18,035			(431	)		(17,283	)		(28,419	)

Earnings (loss) before income taxes		333,773			(192,373	)		4,200			(260,436	)		(114,836	)
Income tax recovery														(98,826	)

Net loss from continuing operations													$	(16,010	)

22 CAMECO CORPORATION

19.

Related parties

The shares of Cameco are widely held and no shareholder, resident in Canada, is allowed to own more than 25% of the Company’s outstanding common shares, either individually or together with associates. A non-resident of Canada is not allowed to own more than 15%.

Related party transactions

Through unsecured shareholder loans, Cameco has agreed to fund Inkai’s project development costs as well as further evaluation on block 3. The limits of the loan facilities are $224,650,000 (US) and advances under these facilities bear interest at a rate of LIBOR plus 2%. At September 30, 2015, $188,377,000 (US) of principal and interest was outstanding (December 31, 2014 - $197,551,000 (US)).

Cameco’s share of the outstanding principal and interest was $100,925,000 at September 30, 2015 (December 31, 2014 - $91,672,000) (note 7). For the quarter ended September 30, 2015, Cameco recorded interest income of $518,000 relating to this balance (2014 - $500,000). For the nine month period ended September 30, 2015, interest income was $1,500,000 (2014 - $1,549,000).

2015 THIRD QUARTER REPORT 23

Exhibit 99.4

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Tim Gitzel, president and chief executive officer of Cameco Corporation, certify that:

1.	I have reviewed this quarterly report on Form 6-K of Cameco Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

Page 2

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 30, 2015


		“Tim Gitzel”
		Tim Gitzel
		President and Chief Executive Officer

Exhibit 99.5

Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

I, Grant Isaac, senior vice-president and chief financial officer, of Cameco Corporation, certify that:

1.	I have reviewed this quarterly report on Form 6-K of Cameco Corporation;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(a)

(b)

(c)

(d)

Page 2

5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)

(b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 30, 2015


		“Grant Isaac”
		Grant Isaac
		Senior Vice-President and Chief Financial Officer

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