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

Exhibit 99.2

Management’s discussion and analysis

for the quarter ended September 30, 2012

Third quarter update	5
Financial results	10
Our operations and development projects	26
Qualified persons	33
Additional information	33

Throughout this document, the terms we, us, our and Cameco mean Cameco Corporation and its subsidiaries.

Management’s discussion and analysis

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, 2012 (interim financial statements). The information is based on what we knew as of October 31, 2012 and updates our first and second quarter and annual MD&A included in our 2011 annual financial review.

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, 2011 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.

Caution about forward-looking information

Our MD&A includes statements and information about our expectations for the future. When we discuss our strategy, plans and future financial and operating performance, or other things that have not yet taken place, we are making statements considered to beforward-looking information orforward-looking statements under Canadian and United States securities laws. We refer to them in this MD&A asforward-looking information.

Key things to understand about the forward-looking information in this MD&A:

• It typically includes words and phrases about the future, such as: anticipate, estimate, expect, plan, will, intend, goal, target, forecast, strategy and outlook (see examples on page 2).

• It represents our current views, and can change significantly.

• It is based on a number ofmaterial 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 thesematerial risks on pages 2 and 3. We recommend you also review our annual information form and our annual, first and second quarter MD&A, which include a discussion of othermaterial 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.

2012 THIRD QUARTER REPORT    1

Examples of forward-looking information in this MD&A

• the discussion under the headingOur strategy

• our plan for increasing annual uranium supply to 36 million pounds by 2018, the expected sources for supply increases and expected production through 2016 at our uranium operations

• our expectation regarding production in our fuel services segment for 2012

• our expectation regarding the closing date for the NUKEM acquisition

• our expectations regarding the timing of the completion of our acquisition of the Yeelirrie uranium project

• our expectations about future global uranium supply, consumption, demand and number of new reactors, including the discussion under the headingUranium market update

• our expectation that our average realized uranium price will improve in the fourth quarter of 2012

• the outlook for each of our operating segments for 2012, and our consolidated outlook for the year

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

• our expectation that our cash position will be substantially lower after we complete the NUKEM and Yeelirrie acquisitions

• our expectations regarding delivery patterns for our uranium and fuel service products

• our expectation that our operating and investment activities in 2012 will not be constrained by the financial covenants in our unsecured revolving credit facility

• our future plans for each of our uranium operating properties, development projects and projects under evaluation, and fuel services operating sites

• our expectations regarding timing for first commissioning in ore and first packaged pounds at Cigar Lake

• our McArthur River mineral reserve and resource estimates

• our forecasts of McArthur River production, operating and capital costs and mine life

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, or are subject to litigation or arbitration that has an adverse outcome

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

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

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

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

• we are affected by political risks in a developing country where we operate

• we are affected by terrorism, sabotage, blockades, civil unrest, 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 and conversion suppliers fail to fulfil delivery commitments

• our Cigar Lake and McArthur River development, mining or production plans are delayed or do not succeed, including infrastructure expansion at McArthur River

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

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

• with respect to the NUKEM and Yeelirrie acquisitions, the risk that closing conditions may not be satisfied in a timely manner, or at all

2    CAMECO CORPORATION

Material assumptions

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

• 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

• our expectations regarding spot prices and realized prices for uranium, and other factors discussed on page 21, Price sensitivity analysis: uranium

• our expectations regarding uranium sales contract terminations, tax rates, foreign currency exchange rates and interest rates

• 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

• the success of our Cigar Lake and McArthur River development, mining and production plans, including infrastructure expansion at McArthur River

• 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

• with respect to the NUKEM and Yeelirrie acquisitions, we have assumed that closing conditions will be satisfied within the expected timeframes

2012 THIRD QUARTER REPORT    3

Our strategy

We remain confident in the long-term fundamentals of the nuclear industry as world demand for safe, clean, reliable and affordable energy continues to grow. Nuclear energy remains an integral part of the energy mix, demonstrated by the 64 reactors under construction today.

However, recent developments in the nuclear industry, primarily centred around Japan, have caused more uncertainty in the rate of growth in nuclear power globally. This led us to review and adjust our outlook, and examine our long-term growth plans.

While market factors continue to evolve, our current view is that over the next decade (to 2021), we expect there will be 80 net new reactors, compared to the 95 previously anticipated. Most of this change is due to the retirement of some reactors and new reactor builds being pushed out beyond the 10-year period. As a result, we have revised our cumulative world uranium demand forecast to 2.1 billion pounds for that period, down 50 million pounds from our previous expectation. As always, we will continue to evaluate the effects on demand as the nuclear market evolves.

Given this expected near-term decrease in demand, we examined our portfolio of projects to determine if we should adjust the timing of development for them. From this review, we have decided to focus primarily on advancing our brownfield projects, while deferring development of our greenfield projects. However, we will undertake some measured activity to preserve the option to bring on these greenfield projects as quickly as possible should market conditions warrant doing so. In addition, we will advance our arrangement with Talvivaara and pace the expansion projects at Inkai. By taking these actions we expect to achieve about 36 million pounds of annual supply rather than 40 million pounds by 2018.

This means we plan to spread our capital spending over a longer period and decrease project-related expenses, which should enhance our nearer term financial picture. Subject to market conditions, we plan to undertake the following projects:

• bring Cigar Lake project to production

• expand production at the McArthur River mine

• refurbish and expand the Key Lake mill

• work to extend the Rabbit Lake mine life

• expand our US ISR production by advancing our various satellite operations

• advance the process for extracting uranium from the Talvivaara mine

Market opportunities will drive the rate of development of the following projects:

• advancing the Millennium project to achieve regulatory approvals as soon as possible to allow development to occur independently

• pacing the increase in uranium production at Inkai blocks 1 and 2 to match progress on the transfer of our refining/conversion technology, both subject to market conditions, and continuing work on the test leach facility at block 3

• completing the value engineering and the environmental permitting at Kintyre, but not proceeding with the detailed feasibility study

Of course, we will adjust the timing of our projects should market conditions evolve, which could change our supply plan. Adjusting a growth plan is not unique in our industry. A number of uranium producers have halted or delayed projects because they are not economic in today’s environment. These economic challenges, driven by continued global economic turmoil and the issues surrounding nuclear power noted above, point to an uncertain future supply of global primary uranium production. And to fuel the 431 currently operating reactors, the 64 reactors under construction today, and the further growth we expect by 2021, new primary sources of production will be needed. We anticipate economics will eventually need to reflect the realities of bringing on new, higher cost production; it’s a matter of timing.

As a result, we continue to prepare our assets now to ensure we can be among the first to respond when the market signals that new production is needed, and project economics improve. We want to be clear that any decision to increase our supply will be driven by profitability.

4    CAMECO CORPORATION

In the meantime, today’s market environment calls for us to increase our focus on execution and maximize efficiencies in order to continually improve our margins to ensure we remain competitive. Specifically, we are in the process of reducing costs at all operations and corporate departments without compromising our values. In addition, we plan to decrease expenditures for exploration and research and development to better match market opportunities.

We maintain a strong balance sheet, which will be enhanced by taking these actions. As part of our normal strategic planning process, we will continue to review our capital structure and asset base to ensure it is optimal.

Our extraordinary assets, extensive portfolio of long-term sales contracts, employee expertise and comprehensive industry knowledge provide us with the confidence that we will be able to achieve these goals. And, as always, we will look for opportunities across the nuclear fuel cycle that we expect will complement and enhance our business.

We will continue to monitor the market closely and adjust our plans accordingly.

See theuranium market updateon page 7 for more information on uranium supply and demand.

Third quarter update

Our performance

Highlights ($ millions except where indicated)			Three months ended September 30							Nine months ended September 30
			2012		2011		change			2012		2011		change
Revenue				408		527		(23	)%		1,363		1,414		(4	)%
Gross profit				135		179		(25	)%		416		423		(2	)%
Net earnings				82		39		110	%		221		186		19	%
$ per common share (diluted)				0.21		0.10		110	%		0.56		0.47		19	%
Adjusted net earnings (non-IFRS, see page 11)				52		104		(50	)%		210		259		(19	)%
$ per common share (adjusted and diluted)				0.13		0.26		(50	)%		0.53		0.66		(20	)%
Cash provided by operations (after working capital changes)				44		192		(77	)%		361		487		(26	)%
Average realized prices	Uranium	$US/lb		44.49		47.33		(6	)%		45.76		47.06		(3	)%
		$Cdn/lb		44.99		45.97		(2	)%		46.22		46.36		—
	Fuel services	$Cdn/kgU		16.98		17.42		(3	)%		17.55		18.04		(3	)%
	Electricity	$Cdn/MWh		54.00		54.00		—			55.00		54.00		2	%

Third quarter

Net earnings attributable to our shareholders (net earnings) this quarter were $82 million ($0.21 per share diluted) compared to $39 million ($0.10 per share diluted) in the third quarter of 2011. In addition to the items noted below, net earnings were impacted by higher mark-to-market gains on foreign exchange derivatives.

On an adjusted basis, our earnings this quarter were $52 million ($0.13 per share diluted) compared to $104 million ($0.26 per share diluted) (non-IFRS measure, see page 11) in the third quarter of 2011, mainly due to:

• lower earnings from our uranium business based on lower sales volumes, lower realized prices and higher costs

• higher expenditures for exploration and administration

• partially offset by higher earnings from our electricity business due to an increase in sales and lower costs

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

2012 THIRD QUARTER REPORT    5

First nine months

Net earnings in the first nine months of the year were $221 million ($0.56 per share diluted) compared to $186 million ($0.47 per share diluted) in the first nine months of 2011. Net earnings were higher than in 2011 due to higher mark-to-market gains on foreign exchange derivatives and the items noted below.

On an adjusted basis, our earnings for the first nine months of this year were $210 million ($0.53 per share diluted) compared to $259 million ($0.66 per share diluted) (non-IFRS measure, see page 11). The change was due to:

• lower earnings from our uranium business based on lower sales volumes, lower realized prices and higher costs

• a $30 million (US) contract termination charge

• higher expenditures for exploration and administration

• partially offset by higher earnings from our electricity business due to an increase in sales, higher realized prices and lower costs

SeeFinancial results by segmenton page 19 for more detailed discussion.

Operations update

		Three months ended September 30							Nine months ended September 30
Highlights		2012		2011		change			2012		2011		change
Uranium	Production volume (million lbs)		5.3		5.3		—			15.4		15.8		(3	)%
	Sales volume (million lbs)		5.1		7.2		(29	)%		18.1		19.1		(5	)%
	Revenue ($ millions)		231		332		(30	)%		837		885		(5	)%
	Gross profit ($ millions)		83		133		(38	)%		267		318		(16	)%
Fuel services	Production volume (million kgU)		2.1		2.8		(25	)%		10.9		11.6		(6	)%
	Sales volume (million kgU)		3.3		4.6		(28	)%		10.1		11.1		(9	)%
	Revenue ($ millions)		56		81		(31	)%		178		199		(11	)%
	Gross profit ($ millions)		3		10		(70	)%		23		29		(21	)%
Electricity	Output (100%) (TWh)		7.1		6.7		6	%		19.6		18.7		5	%
	Revenue (100%) ($ millions)		384		362		6	%		1,095		1,016		8	%
	Our share of earnings before taxes ($ millions)		46		35		31	%		125		75		67	%

Production in our uranium segment this quarter was unchanged compared to the third quarter of 2011. For the first nine months, production was 3% lower than for the same period in 2011 mainly due to lower production at Smith Ranch-Highland. SeeUranium 2012 Q3 updates starting on page 28 for more information.

Key highlights:

• at McArthur River, mineral reserves increased by 19%. See pages 28 and 29 for more information

• at Inkai, we signed a memorandum of agreement with our joint venture partner, Kazatomprom, setting out a framework to increase uranium production and extend the duration of the mining licences at the Inkai operation, in conjunction with the joint development of a uranium refinery in Kazakhstan. See pages 31 and 32 for more information.

• in Saskatchewan, we received a funding commitment from the provincial government to construct a highway connecting McArthur River and Cigar Lake. See page 28 for more information.

Production in our fuel services segment was 25% lower this quarter than in the third quarter of 2011, and 6% lower for the first nine months compared to last year due to lower planned production in 2012. We continue to expect production to be between 13 million and 14 million kgU this year.

6    CAMECO CORPORATION

In our electricity segment, BPLP’s generation was 6% higher for the quarter and 5% higher for the first nine months of the year compared to the same periods last year. The capacity factor this quarter was 99% and 92% for the first nine months.

Also of note this quarter:

On August 26, we announced an agreement with BHP Billiton to acquire the Yeelirrie uranium project in Western Australia for $430 million (US). Yeelirrie is a near-surface calcrete-style deposit, amenable to open pit mining techniques.

We expect the transaction to close by the end of 2012, subject to the receipt of approvals from the government of Western Australia and the Australian Foreign Investment Review Board. Upon closing, stamp duty of about $22 million (US) will also be payable to the government of Western Australia.

After closing, next steps will be for us to conduct a full document review of the project and develop plans for future necessary work.

Uranium market update

Since the previous quarter, the nuclear industry continues to experience near- to medium-term uncertainty, driven primarily by the evolving situation in Japan.

In September 2012, a Japanese government panel announced a draft energy policy that included plans to phase out nuclear power generation by 2040. But the plan drew intense opposition from business groups and communities whose economies depend on the local nuclear power plants. The Japanese government did not adopt the plan, but agreed to take it under consideration while engaging with local governments, the public and the international community in developing an energy policy.

Japan’s new Nuclear Regulatory Authority (NRA) also came into effect in September. It will create new regulatory standards against which reactor restarts will be evaluated. We believe the NRA brings important stability to the regulatory environment in Japan and has already brought some clarity to the issue of reactor restarts. It indicated that no additional reactors will be restarted until the new standards are in place – a process expected to take about 10 months. This requirement suggests there will be no more reactor restarts in Japan this year and possibly not until mid-2013 or later depending on when the standards are put in place.

The slower reactor restarts expected in Japan, combined with slower economic growth worldwide and changes to nuclear programs in some other countries led us to re-examine our reactor forecast. For example, Canada, France and Belgium have announced plans to retire their older reactors, and India has revised its 2020 nuclear target down from 20 to 14.6 gigawatts. So while the market continues to evolve, our initial review results in an estimated 80 net new reactors over the period 2012 to 2021, compared to the 95 we expected earlier this year. Most of the decrease is due to the retirement of reactors, although some is also due to deferrals beyond 2021.

2012 THIRD QUARTER REPORT    7

New Build Outlook – Planned Reactors (2012 to 2021)

Region / Country			Previous Forecast								Change to			New Forecast
(as of Sept 30, 2012)	Operable		New		Shut			Net New			net new			Net New			Operable 2021
Americas		127		11		(6	)		5			(1	)		4			131
Europe		137		11		(14	)		(3	)		(3	)		(6	)		131
Asia		77		14		(1	)		13			(8	)		5			82
Other*		6		7		—			7			—			7			13
India		20		15		—			15			(3	)		12			32
China		15		52		—			52			—			52			67
Russia/E. Europe**		49		17		(11	)		6			—			6			55
Total		431		127		(32	)		95			(15	)		80			511

* Other includes Iran, Pakistan, South Africa, Turkey and United Arab Emirates.

** Eastern Europe includes Armenia, Belarus and Ukraine.

Of these net new reactors, 64 are under construction today. China is the most aggressive, and we expect it to grow its nuclear power program from the 15 currently operating reactors to 67 in 2021, of which 26 are under construction.

The 80 net new reactors combined with the current base of nuclear power plants translates into a cumulative uranium demand of about 2.1 billion pounds to 2021, which is down by about 50 million pounds from our earlier forecast.

While expected demand has decreased, there has also been an increase in global supply. In China, Uzbekistan and Namibia production increased at a number of mines, which we expect will equate to about 30 million pounds of further supply over the 10-year period.

The result when we put these changes to supply and demand together is a demonstrated need for new supply of 360 million pounds from 2012 to 2021, compared to the 440 million pounds we had forecast earlier in the year.

However, the current market environment also poses challenges to bringing on new supply and could impact supply expectations as conditions continue to evolve. A number of project deferrals and cancellations have been announced as producers have reacted to lower uranium prices and general economic pressures. As well, secondary supplies continue to diminish, particularly with the end of the Russian Highly Enriched Uranium (HEU) agreement in 2013. Conclusion of this arrangement will mean the removal of 24 million pounds of relatively low-cost secondary annual uranium supply from the market, and there are no indications of a second Russian HEU deal.

Despite the changes we see to the supply/demand outlook, what remains clear is that new supply will be needed. Though some could come from additions to secondary supplies, the majority will need to come from new mines and expansions to existing mines at a time when pursuing such projects is becoming increasingly difficult. In addition, the long-term fundamentals of the industry remain strong, with 64 reactors currently under construction and some of the growth pushed further out in time. As a result, we are managing our assets through this period of uncertainty with a focus on safety, efficiency and profitable growth.

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

This discussion of our expectations for the nuclear industry, including its growth profile and future global uranium supply and demand and the number of reactors, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the headingCaution about forward-looking information beginning on page 1.

8    CAMECO CORPORATION

Industry prices

	Sep 30 2012		Jun 30 2012		Mar 31 2012		Sep 30 2011		Jun 30 2011		Mar 31 2011
Uranium ($US/lb U3O8) 1
Average spot market price		46.50		50.75		51.05		52.25		52.88		60.50
Average long-term price		60.50		61.25		60.00		63.50		68.00		70.00
Fuel services ($US/kgU UF6)1
Average spot market price
North America		9.25		6.63		6.63		9.50		11.00		12.00
Europe		9.75		7.00		7.00		9.50		11.00		12.00
Average long-term price
North America		16.75		16.75		16.75		16.50		16.00		15.75
Europe		17.25		17.25		17.25		17.00		16.25		16.00
Note: the industry does not publish UO2prices.
Electricity ($/MWh)
Average Ontario electricity spot price		28.00		19.00		20.00		33.00		28.00		32.00

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

On the spot market, where purchases call for delivery within one year, the volume reported for the third quarter of 2012 was just over 9 million pounds. This compares to about 13 million pounds in the third quarter of 2011.

Continued uncertainty in the market contributed to downward pressure on the spot price. At the end of the quarter, the average spot price was $46.50 (US) per pound. On October 29, 2012, Ux reported a spot price of $42.50 (US) per pound. In general, utilities are well covered under existing contracts, so we expect uranium demand in the near term to remain somewhat discretionary.

The long-term uranium price held relatively firm during the quarter. Long-term contracts usually call for deliveries to begin more than two years after the contract is finalized, and use a number of pricing formulas, including fixed prices adjusted by inflation indices, and market referenced prices (spot and long-term indicators quoted near the time of delivery).

Spot UF₆ conversion prices increased significantly during the quarter, in part due to a shutdown at one of the primary UF₆conversion facilities. Long-term UF₆ conversion price indicators held firm throughout the quarter.

Long-term fundamentals are strong

Electricity is essential to maintaining and improving the standard of living for people throughout the world, and nuclear power continues to be an affordable and sustainable source of safe, clean, reliable energy. New reactors are currently under construction around the world and the demand for uranium is expected to grow, and along with it, the need for new supply to meet future customer requirements.

Our long history of success comes from many years of hard work and discipline, developing and acquiring the expertise and assets we need to deliver on our strategy. We are well positioned to grow and be successful, and to build value for our shareholders.

Shares and stock options outstanding

At October 30, 2012, we had:

• 395,349,044 common shares and one Class B share outstanding

• 9,579,845 stock options outstanding, with exercise prices ranging from $15.79 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.

2012 THIRD QUARTER REPORT    9

Financial results

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

2012 Q3 results
Consolidated financial results	10
Outlook for 2012	16
Liquidity and capital resources	17
Financial results by segment	19
Uranium	19
Fuel services	23
Electricity	24

Consolidated financial results

Highlights	Three months ended September 30							Nine months ended September 30
($ millions except per share amounts)	2012		2011		change			2012		2011		change
Revenue		408		527		(23	)%		1,363		1,414		(4	)%
Gross profit		135		179		(25	)%		416		423		(2	)%
Net earnings		82		39		110	%		221		186		19	%
$ per common share (basic)		0.21		0.10		110	%		0.56		0.47		19	%
$ per common share (diluted)		0.21		0.10		110	%		0.56		0.47		19	%
Adjusted net earnings (non-IFRS, see page 11)		52		104		(50	)%		210		259		(19	)%
$ per common share (adjusted and diluted)		0.13		0.26		(50	)%		0.53		0.66		(20	)%
Cash provided by operations (after working capital changes)		44		192		(77	)%		361		487		(26	)%

Net earnings

Net earnings this quarter were $82 million ($0.21 per share diluted) compared to $39 million ($0.10 per share diluted) in the third quarter of 2011. In addition to the items noted below, net earnings were impacted by higher mark-to-market gains on foreign exchange derivatives.

On an adjusted basis, our earnings this quarter were $52 million ($0.13 per share diluted) compared to $104 million ($0.26 per share diluted) (non-IFRS measure, see page 11) in the third quarter of 2011, mainly due to:

• lower earnings from our uranium business based on lower sales volumes, lower realized prices and higher costs

• higher expenditures for exploration and administration

• partially offset by higher earnings from our electricity business

10    CAMECO CORPORATION

Net earnings in the first nine months of the year were $221 million ($0.56 per share diluted) compared to $186 million ($0.47 per share diluted) in the first nine months of 2011. Net earnings were higher than in 2011 due to higher mark-to-market gains on foreign exchange derivatives and the items noted below.

On an adjusted basis, our earnings for the first nine months of this year were $210 million ($0.53 per share diluted) compared to $259 million ($0.66 per share diluted) (non-IFRS measure, see page 11). The change was due to:

• lower earnings from our uranium business based on lower sales volumes, lower realized prices and higher costs

• a $30 million (US) contract termination charge

• higher expenditures for exploration and administration

• partially offset by higher earnings from our electricity business due to an increase in sales, higher realized prices and lower costs

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.

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

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

	Three months ended September 30						Nine months ended September 30
($ millions)	2012			2011			2012			2011
Net earnings		82			39			221			186
Adjustments
Adjustments on derivatives1 (pre-tax)		(40	)		88			(15	)		100
Income taxes on adjustments to derivatives		10			(23	)		4			(27	)
Adjusted net earnings		52			104			210			259

¹  In 2008, we opted to discontinue hedge accounting for our portfolio of foreign currency forward sales contracts. Since then, we have adjusted our gains or losses on derivatives to reflect what our earnings would have been had hedge accounting been applied.

2012 THIRD QUARTER REPORT    11

The table that follows describes what contributed to the changes in adjusted net earnings this quarter.

Change in adjusted net earnings ($ millions)			Three months ended September 30			Nine months ended September 30
Adjusted net earnings – 2011				104			259
Change in gross profit by segment		(we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits)
Uranium	Lower sales volumes			(38	)		(16	)
	Lower realized prices ($US)			(15	)		(24	)
	Foreign exchange impact on realized prices			10			21
	Higher costs			(6	)		(32	)
	Hedging benefits			1			(19	)
	change - uranium			(48	)		(70	)
Fuel services	Lower sales volumes			(3	)		(2	)
	Lower realized prices ($Cdn)			(1	)		(5	)
	(Higher) lower costs			(3	)		1
	Hedging benefits			—			(2	)
	change – fuel services			(7	)		(8	)
Electricity	Higher sales volumes			3			4
	Higher realized prices ($Cdn)			—			9
	Lower costs			10			37
	change – electricity			13			50
Other changes
Higher exploration expenditures				(3	)		(13	)
Higher administration expenditures				(1	)		(18	)
Lower income taxes				9			44
Contract termination charge				—			(30	)
Financing costs				(3	)		(3	)
Other				(12	)		(1	)
Adjusted net earnings – 2012				52			210

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

Average realized prices

		Three months ended September 30							Nine months ended September 30
		2012		2011		change			2012		2011		change
Uranium	$US/lb		44.49		47.33		(6	)%		45.76		47.06		(3	)%
	$Cdn/lb		44.99		45.97		(2	)%		46.22		46.36		—
Fuel services	$Cdn/kgU		16.98		17.42		(3	)%		17.55		18.04		(3	)%
Electricity	$Cdn/MWh		54.00		54.00		—			55.00		54.00		2	%

12    CAMECO CORPORATION

Quarterly trends

Highlights	2012							2011								2010
($ millions except per share amounts)	Q3		Q2			Q1		Q4		Q3		Q2		Q1		Q4
Revenue		408		391			564		970		527		426		461		673
Net earnings		82		8			131		265		39		55		92		206
$ per common share (basic)		0.21		0.02			0.33		0.67		0.10		0.14		0.23		0.52
$ per common share (diluted)		0.21		0.02			0.33		0.67		0.10		0.14		0.23		0.52
Adjusted net earnings (non-IFRS, see page 11)		52		34			124		249		104		71		84		190
$ per common share (adjusted and diluted)		0.13		0.09			0.31		0.63		0.26		0.18		0.22		0.48
Cash provided by operations (after working capital changes)		44		(94	)		411		258		192		23		271		111

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

	2012									2011												2010
($ millions)	Q3			Q2			Q1			Q4			Q3			Q2			Q1			Q4
Net earnings		82			8			131			265			39			55			92			206
Adjustments
Adjustments on derivatives1 (pre-tax)		(40	)		35			(10	)		(22	)		88			22			(10	)		(22	)
Income taxes on adjustments to derivatives		10			(9	)		3			6			(23	)		(6	)		2			6
Adjusted net earnings (non-IFRS, see page 11)		52			34			124			249			104			71			84			190

¹  In 2008, we opted to discontinue hedge accounting for our portfolio of foreign currency forward sales contracts. Since then, we have adjusted our gains or losses on derivatives to reflect what our earnings would have been had hedge accounting been applied.

Key things to note:

• our financial results are strongly influenced by the performance of our uranium segment, which accounted for 57% of consolidated revenues in the third quarter of 2012

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

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

• cash from operations tends to fluctuate as a result of the timing of deliveries and product purchases in our uranium and fuel services segments

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

2012 THIRD QUARTER REPORT    13

Administration

	Three months ended September 30							Nine months ended September 30
($ millions)	2012		2011		change			2012		2011		change
Direct administration		37		37		—			110		101		9	%
Stock-based compensation		2		1		100	%		14		5		180	%
Total administration		39		38		3	%		124		106		17	%

Direct administration costs were unchanged this quarter and $9 million higher for the first nine months compared to the same periods last year. The increase in the first nine months reflects the following:

• studies and analyses of various opportunities

• enhancements to information systems

Stock-based compensation expenses were $14 million for the first nine months of 2012 compared to $5 million for the same period in 2011. Our share price was nearly level in the first nine months of 2012, whereas it declined markedly in the first half of 2011.

Exploration

Uranium exploration expenses were $35 million this quarter compared to $32 million in the same quarter in 2011, as exploration activity in Saskatchewan increased. Exploration expenses in the first nine months of the year increased to $75 million from $62 million in 2011. We expect exploration expenses to be about 15% to 20% higher than they were in 2011 due to an increase in evaluation activities at Kintyre and Inkai block 3. We are also continuing to focus efforts in Canada and the United States.

Income taxes

In the third quarter of 2012, we recorded an income tax expense of $3 million compared to a recovery of $22 million in the third quarter of 2011. The expense this quarter was mainly due to higher pre-tax earnings related largely to the recording of $53 million in gains on derivatives in 2012 compared to losses of $76 million in 2011. The distribution of earnings between jurisdictions was also different compared to 2011. In 2012, we recorded losses of $2 million in Canada compared to $186 million in 2011, whereas earnings in foreign jurisdictions declined to $86 million from $203 million. The tax rate in Canada is higher than the average of the rates in the foreign jurisdictions in which we operate.

On an adjusted basis, we recorded an income tax recovery of $7 million this quarter compared to an expense of $2 million in the third quarter of 2011. Our effective tax rate this quarter on an adjusted net earnings basis reflects a recovery of 17% compared to an expense of 1% for the third quarter of 2011.

In the first nine months of 2012, we recorded an income tax recovery of $33 million compared to a recovery of $19 million in 2011. The increase in recovery for the first nine months of the year was mainly due to a change in the distribution of earnings. Also, we received additional certainty on particular tax provisions that allowed us to recognize a $9 million recovery in our income tax expense.

On an adjusted basis, we recorded an income tax recovery of $37 million in the first nine months of 2012 compared to an expense of $8 million in 2011. Our effective tax rate for the first nine months of 2012, on an adjusted net earnings basis, reflects a recovery of 21% compared to an expense of 3% in 2011.

14    CAMECO CORPORATION

	Three months ended September 30									Nine months ended September 30
($ millions)	2012			2011			change			2012			2011			change
Pre-tax Adjusted Earnings1
Canada2		(41	)		(98	)		58	%		(182	)		(160	)		(14	)%
Foreign		86			203			(58	)%		354			427			(17	)%
Total pre-tax adjusted earnings		45			105			(57	)%		172			267			(36	)%
Adjusted Income Taxes1
Canada2		(7	)		(12	)		42	%		(46	)		(27	)		(70	)%
Foreign		—			14			(100	)%		9			35			(74	)%
Adjusted income tax expense (recovery)		(7	)		2			(450	)%		(37	)		8			(563	)%
Effective tax rate		(17	)%		1	%		(1800	)%		(21	)%		3	%		(800	)%

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 11).

Foreign exchange

At September 30, 2012:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $0.98 (Cdn), down from $1.00 (US) for $1.02 (Cdn) at June 30, 2012. The exchange rate averaged $1.00 (US) for $1.00 (Cdn) over the quarter.

• We had foreign currency contracts of $1.2 billion (US) and EUR 105 million at September 30, 2012. The US currency contracts had an average exchange rate of $1.00 (US) for $1.02 (Cdn).

• The mark-to-market gain on all foreign exchange contracts was $44 million compared to an $8 million loss at June 30, 2012. We received cash of $3 million this quarter related to the settlement of foreign exchange contracts.

2012 THIRD QUARTER REPORT    15

Outlook for 2012

Our outlook for 2012 reflects the growth expenditures necessary to help us achieve our strategy. Our outlook for consolidated capital expenditures and consolidated tax rate has changed. We explain the changes below. All other items in the table are unchanged. We do not provide an outlook for the items in the table that are marked with a dash.

SeeFinancial results by segment on page 19 for details.

2012 Financial outlook

	Consolidated	Uranium	Fuel services	Electricity
Production	—	21.7 million lbs	13 to 14 million kgU	—
Sales volume	—	31 to 33 million lbs	Decrease 10% to 15%	—
Capacity factor	—	—	—	93%
Revenue compared to 2011	Decrease 0% to 5%	Decrease 0% to 5%1	Decrease 10% to 15%	Increase 5% to 10%
Average unit cost of sales (including D&A)	—	Increase 0% to 5%2	Increase 10% to 15%	Decrease 15% to 20%
Direct administration costs compared to 20113	Increase 10% to 15%	—	—	—
Exploration costs compared to 2011	—	Increase 15% to 20%	—	—
Tax rate	Recovery of 10% to 15%	—	—	—
Capital expenditures	$730 million4	—	—	$70 million

¹  Based on a uranium spot price of $42.50 (US) per pound (the Ux spot price as of October 29, 2012), a long-term price indicator of $60.00 (US) per pound (the Ux long-term indicator on September 30, 2012) and an exchange rate of $1.00 (US) for $1.00 (Cdn).

²  This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we decide to make discretionary purchases in 2012 then we expect the average unit cost of sales to increase further.

³  Direct administration costs do not include stock-based compensation expenses. See page 14 for more information.

⁴  Does not include our share of capital expenditures at BPLP.

Our customers choose when in the year to receive deliveries of uranium and fuel services products, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly. In the fourth quarter, we expect about 40% of our 2012 deliveries to occur with an improvement in our average realized uranium price due to pricing under the mix of contracts.

We now expect a recovery of 10% to 15% for our consolidated tax rate (previously a 5% to 10% recovery). The change is primarily related to the $9 million recovery in our income tax expense that we recognized in the second quarter due to additional certainty we received on particular tax provisions.

We now expect our capital expenditures to be about $730 million compared to our previous estimate of $680 million due to changes in scope and scheduling of some of our projects in northern Saskatchewan.

Sensitivity analysis

For the rest of 2012:

• a change of $5 (US) per pound in both the Ux spot price ($42.50 (US) per pound on October 29, 2012) and the Ux long-term price indicator ($60.00 (US) per pound on September 30, 2012) would change revenue by $13 million and net earnings by $7 million

16    CAMECO CORPORATION

• a change of $5/MWh in the electricity spot price would change our 2012 net earnings by $1 million based on the assumption that the spot price will remain below the floor price of $51.62/MWh provided under BPLP’s agreement with the Ontario Power Authority (OPA)

• a one-cent change in the value of the Canadian dollar versus the US dollar would change revenue by $2 million and adjusted net earnings by $1 million. This sensitivity is based on an exchange rate of $1.00 (US) for $1.02 (Cdn).

Liquidity and capital resources

Our financial objective is to make sure we have the cash and debt capacity to fund our operating activities, investments and growth. Over the past nine months we have announced three acquisitions:

• Millennium, which closed in June for $150 million in cash

• NUKEM, expected to close by the end of the year (subject to regulatory approvals) and to use about $250 million (US) of cash

• Yeelirrie, expected to close by the end of the year (subject to regulatory approvals) and to use about $452 million (US) of cash, including the purchase price of $430 million (US) and a stamp duty of about $22 million (US) paid to the government of Western Australian upon close

Once complete, our current cash position is expected to be substantially lower. In addition, we expect to continue investing in expanding our production capacity over the next several years.

We have a number of alternatives to fund this continued growth 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 that we can take advantage of favourable market conditions when they arise.

Cash from operations

Cash from operations was $148 million lower this quarter than in 2011 due largely to lower uranium deliveries. Working capital required $72 million more in 2012 largely as a result of an increase in uranium inventories during the quarter. Not including working capital requirements, our operating cash flows this quarter were lower by $77 million, based on lower profits in our uranium segment. SeeFinancial results by segment on page 19 for details.

Cash from operations was $126 million lower for the first nine months of 2012 than for the same period in 2011 mainly due to lower uranium profits and lower sales volumes, partially offset by higher profits from the electricity business. Not including working capital requirements, our operating cash flows in the first nine months were down by $120 million.

Debt

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $1.9 billion at September 30, 2012, the same as at June 30, 2012. At September 30, 2012, we had approximately $669 million outstanding in letters of credit.

Debt covenants

We are bound by certain covenants in our unsecured revolving credit facility. The financially related covenants place restrictions on total debt, including guarantees. As at September 30, 2012, we met these financial covenants and do not expect our operating and investment activities for the remainder of 2012 to be constrained by them.

Long-term contractual obligations and off-balance sheet arrangements

We had two kinds of off-balance sheet arrangements at September 30, 2012:

• purchase commitments

• financial assurances

2012 THIRD QUARTER REPORT    17

Other than the NUKEM and the Yeelirrie agreements noted on page 17, as well as the purchase of an incremental interest in the Millennium project for $150 million which closed in June 2012, there have been no material changes to our long-term contractual obligations, purchase commitments and financial assurances since December 31, 2011, including payments due for the next five years and thereafter. Our long-term contractual obligations do not include our sales commitments. Please see our annual MD&A for more information.

Balance sheet

($ millions)	Sep 30, 2012		Dec 31, 2011		change
Cash and short-term investments		664		1,202		(45	)%
Total debt		993		1,039		(4	)%
Inventory		719		494		46	%

Total cash and short-term investments at September 30, 2012 were $664 million, or 45% lower than at December 31, 2011 due to a higher rate of capital expenditures and our purchase of an incremental interest in the Millennium project. Net debt at September 30, 2012 was $329 million.

Total debt decreased by $46 million to $993 million at September 30, 2012. Of this total, $79 million was classified as current, down $34 million compared to December 31, 2011. See notes 16 and 17 of our audited annual financial statements for more detail.

Total product inventories increased to $719 million. Uranium inventories increased, as sales were lower than production and purchases in the first nine months of the year. Fuel services inventories increased as sales were also lower than production and purchases.

18    CAMECO CORPORATION

Financial results by segment

Uranium

Highlights	Three months ended September 30							Nine months ended September 30
	2012		2011		change			2012		2011		change
Production volume (million lbs)		5.3		5.3		—			15.4		15.8		(3	)%
Sales volume (million lbs)		5.1		7.2		(29	)%		18.1		19.1		(5	)%
Average spot price ($US/lb)		48.08		51.04		(6	)%		50.38		57.89		(13	)%
Average long-term price ($US/lb)		60.67		65.33		(7	)%		60.67		68.22		(11	)%
Average realized price
($US/lb)		44.49		47.33		(6	)%		45.76		47.06		(3	)%
($Cdn/lb)		44.99		45.97		(2	)%		46.22		46.36		—
Average unit cost of sales ($Cdn/lb U3O8) (including D&A)		28.75		27.59		4	%		31.47		29.68		6	%
Revenue ($ millions)		231		332		(30	)%		837		885		(5	)%
Gross profit ($ millions)		83		133		(38	)%		267		318		(16	)%
Gross profit (%)		36		40		(10	)%		32		36		(11	)%

Third quarter

Production volumes this quarter were unchanged compared to the third quarter of 2011. SeeUranium 2012 Q3 updates starting on page 28 for more information.

Uranium revenues this quarter were down 30% compared to 2011, due to a 29% decrease in sales volumes and a 2% decrease in the $Cdn realized selling price.

Our realized prices this quarter were lower than the third quarter of 2011 mainly due to lower $US prices under fixed-price contracts. In the third quarter of 2012, our realized foreign exchange rate was $1.01, compared to $0.97 for the prior year.

Total cost of sales (including D&A) decreased by 26% ($147 million compared to $199 million in 2011). This was mainly the result of the following:

• a 29% decrease in sales volumes

• lower royalty charges ($7 million in 2012; $26 million in 2011) due to decreased deliveries of Saskatchewan-produced material

• partially offset by average unit costs for produced uranium being 16% higher due to increased non-cash production costs at our ISR locations

The net effect was a $50 million decrease in gross profit for the quarter.

First nine months

Production volumes for the first nine months of the year were lower than in the previous year due to lower output at Smith Ranch-Highland and Inkai. SeeUranium 2012 Q3 updateson page 28 for more information.

For the first nine months of 2012, uranium revenues were down 5% compared to 2011, due to a 5% decrease in sales volumes.

Our $US realized prices were lower than the first nine months of 2011 mainly due to lower prices under market-related contracts being offset by a more favourable exchange rate. In the first nine months of 2012, our realized foreign exchange rate was $1.01 compared to $0.99 in the prior year.

2012 THIRD QUARTER REPORT    19

Total cost of sales (including D&A) increased by 1% ($570 million compared to $567 million in 2011). This was mainly the result of the following:

• average unit costs for produced uranium were 13% higher due to increased unit production costs relating mainly to the lower production during the first nine months. We continue to expect our average unit cost of sales (including D&A) to increase by 0% to 5% for the year compared to 2011.

• royalty charges in 2012 were $2 million higher due to increased deliveries of Saskatchewan-produced material

• partially offset by a 5% decrease in sales volume

The net effect was a $51 million decrease in gross profit for the first nine months.

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

($Cdn/lb)	Three months ended September 30							Nine months ended September 30
	2012		2011		change			2012		2011		change
Produced
Cash cost Non-cash cost		21.11 8.62		17.89 7.79		18 11	%  %		21.18 8.01		18.87 6.92		12 16	%  %
Total production cost		29.73		25.68		16	%		29.19		25.79		13	%
Quantity produced (million lbs)		5.3		5.3		—			15.4		15.8		(3	)%
Purchased
Cash cost		26.08		17.90		46	%		27.04		28.32		(5	)%
Quantity purchased (million lbs)		4.6		3.1		48	%		8.4		7.3		15	%
Totals
Produced and purchased costs		28.03		22.81		23	%		28.43		25.36		12	%
Quantities produced and purchased (million lbs)		9.9		8.4		18	%		23.8		23.1		3	%

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 quarters and first nine months of 2012 and 2011.

20    CAMECO CORPORATION

Cash and total cost per pound reconciliation

($ millions)	Three months ended September 30									Nine months ended September 30
	2012			2011			change			2012			2011			change
Cost of product sold		121.8			164.7			(26	)%		480.6			487.5			(1	)%
Add / (subtract)
Royalties		(6.7	)		(26.3	)		(75	)%		(64.3	)		(62.3	)		3	%
Standby charges		(8.0	)		(5.2	)		54	%		(20.9	)		(16.0	)		31	%
Other selling costs		(0.6	)		(0.6	)		—			(2.9	)		(6.7	)		(57	)%
Change in inventories		125.4			17.7			608	%		160.9			102.5			57	%
Cash operating costs(a)		231.9			150.3			54	%		553.4			505.0			10	%
Add / (subtract)
Depreciation and amortization		25.7			34.3			(25	)%		89.5			79.1			13	%
Change in inventories		19.9			7.0			184	%		33.7			1.7			1882	%
Total operating costs(b)		277.5			191.6			45	%		676.6			585.8			16	%
Uranium produced & purchased (millions lbs) (c)		9.9			8.4			18	%		23.8			23.1			3	%
Cash costs per pound(a ÷ c)		23.42			17.89			31	%		23.25			21.86			6	%
Total costs per pound(b ÷ c)		28.03			22.81			23	%		28.43			25.36			12	%

Price sensitivity analysis: uranium

The table below isnot a forecast of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table.

It is designed to indicate how our portfolio of long-term contracts would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same and none of the assumptions we list below change.

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

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)

($US/lb U3O8)
Spot prices	$	20	$	40	$	60	$	80	$	100	$	120	$	140
2012		46		46		49		50		52		53		55
2013		42		46		54		63		72		81		89
2014		45		48		56		64		73		82		89
2015		41		46		56		66		76		87		96
2016		44		49		58		68		78		88		97

The table illustrates the mix of long-term contracts in our portfolio, and is consistent with our contracting strategy. The changes to the table in the quarter are mainly due to:

• deliveries made and contracts entered into

• changes to deliveries under some contracts where deliveries are tied to reactor requirements

2012 THIRD QUARTER REPORT    21

Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. We signed many of our current contracts in 2003 to 2005, when market prices were low ($11 to $31 (US)). Those that are fixed at lower prices or have low ceiling prices will yield prices that are lower than current market prices. These older contracts are beginning to expire, and we are starting to deliver into more favourably priced contracts.

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 32 million pounds per year   Deliveries   •    customers take the maximum quantity allowed under each contract (unless they have already provided a delivery notice indicating they will take less)   •    we defer a portion of deliveries under existing contracts for 2012     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 14% higher than the spot price. This differential has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table will be higher.   •    we deliver all volumes that we don’t have contracts for at the spot price for each scenario   Inflation   •    is 2% per year

22    CAMECO CORPORATION

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

Highlights	Three months ended September 30							Nine months ended September 30
	2012		2011		change			2012		2011		change
Production volume (million kgU)		2.1		2.8		(25	)%		10.9		11.6		(6	)%
Sales volume (million kgU)		3.3		4.6		(28	)%		10.1		11.1		(9	)%
Realized price ($Cdn/kgU)		16.98		17.42		(3	)%		17.55		18.04		(3	)%
Average unit cost of sales ($Cdn/kgU) (including D&A)		16.20		15.34		6	%		15.32		15.42		(1	)%
Revenue ($ millions)		56		81		(31	)%		178		199		(11	)%
Gross profit ($ millions)		3		10		(70	)%		23		29		(21	)%
Gross profit (%)		5		12		(58	)%		13		15		(13	)%

Third quarter

Production volumes in the quarter were 25% lower than in 2011 due to the reduction of planned production for 2012.

Total revenue was $25 million lower than in 2011 due to a 28% decline in deliveries of our fuel services products and a 3% decline in the realized selling price.

Our $Cdn realized price for fuel services was affected by the mix of products delivered in the quarter. In 2012, a higher proportion of fuel services sales were for UF₆, which typically yields a lower price than the other fuel services products.

The total cost of sales (including D&A) decreased by 25% ($53 million compared to $71 million in 2011) due to the decrease in the sales volumes. The average unit cost of sales was 6% higher due to the mix of products delivered in the quarter.

The net effect was a decrease of $7 million in gross profit for the quarter.

First nine months

Production was 10.9 million kgU, 6% lower than the same period last year. As a result of the planned reduction in production, results will remain lower than comparable periods in 2011; production remains on track for the year.

Total revenue decreased by 11% due to a 9% decrease in sales volumes and a 3% decline in the realized selling price.

The total cost of sales (including D&A) decreased by 9% ($155 million compared to $170 million in 2011) due to the decrease in the sales volume. The average unit cost of sales was similar to the first nine months of 2011.

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

2012 THIRD QUARTER REPORT    23

Electricity

BPLP

(100% – not prorated to reflect our 31.6% interest)

Highlights ($ millions except where indicated)	Three months ended September 30									Nine months ended September 30
	2012			2011			change			2012			2011			change
Output—terawatt hours (TWh)		7.1			6.7			6	%		19.6			18.7			5	%
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		99	%		93	%		6	%		92	%		87	%		6	%
Realized price ($/MWh)		54			54			—			55	1		54	2		2	%
Average Ontario electricity spot price ($/MWh)		28			33			(15	)%		22			31			(29	)%
Revenue		384			362			6	%		1,095			1,016			8	%
Operating costs (net of cost recoveries)		223			232			(4	)%		668			735			(9	)%
Cash costs		167			182			(8	)%		504			592			(15	)%
Non-cash costs		56			50			12	%		164			143			15	%
Income before interest and finance charges		161			130			24	%		427			281			52	%
Interest and finance charges		10			14			(29	)%		20			30			(33	)%
Cash from operations		91			137			(34	)%		442			376			18	%
Capital expenditures		52			61			(15	)%		140			158			(11	)%
Distributions		95			80			19	%		285			205			39	%
Capital calls		17			—			—			50			11			355	%
Operating costs ($/MWh)		31			35			(11	)%		33	1		39	2		(15	)%

¹  Nine months ended September 30, 2012 are based on actual generation of 19.6 TWh plus deemed generation of 0.4 TWh

²  Nine months ended September 30, 2011 are based on actual generation of 18.7 TWh plus deemed generation of 0.2 TWh

Our earnings from BPLP

Highlights ($ millions except where indicated)	Three months ended September 30									Nine months ended September 30
	2012			2011			change			2012			2011			change
BPLP’s earnings before taxes (100%)		151			116			30	%		407			251			62	%
Cameco’s share of pretax earnings before adjustments (31.6%)		48			37			30	%		129			79			63	%
Proprietary adjustments		(2	)		(2	)		—			(4	)		(4	)		—
Earnings before taxes from BPLP		46			35			31	%		125			75			67	%

Third quarter

Total electricity revenue increased by 6% this quarter compared to the third quarter of 2011 due to higher output. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA and financial contract revenue. BPLP recognized revenue of $166 million this quarter under its agreement with the OPA, compared to $119 million in the third quarter of 2011. About 72% of BPLP’s output was sold under financial contracts this quarter

24    CAMECO CORPORATION

compared to 53% in the third quarter of 2011. From time to time BPLP enters the market to lock in the gains under these contracts. Gains on BPLP’s contracting activity were slightly lower than in 2011.

The capacity factor was 99% this quarter, up from 93% in the third quarter of 2011 as a result of no planned outage days. Operating costs were slightly lower at $223 million compared to $232 million in 2011.

The result was a $11 million increase in our share of earnings before taxes.

BPLP distributed $95 million to the partners in the third quarter; our share was $30 million. Also, BPLP made capital calls of $17 million to the partners in the third quarter; our share was $5 million. The partners have agreed that BPLP will distribute excess cash monthly and will make separate cash calls for major capital projects.

First nine months

Total electricity revenue for the first nine months increased 8% compared to 2011 due to higher output and higher realized prices. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA and financial contract revenue. BPLP recognized revenue of $575 million in the first nine months of 2012 under its agreement with the OPA, compared to $351 million in the first nine months of 2011. The equivalent of about 67% of BPLP’s output was sold under financial contracts in the first nine months of this year, compared to 49% in 2011. From time to time BPLP enters the market to lock in the gains under these contracts. Gains on BPLP’s contracting activity were slightly higher than in 2011.

The capacity factor was 92% for the first nine months of this year, up from 87% in the third quarter of 2011 due to a lower volume of outage days during this year’s planned outage compared to last year’s planned outage. Operating costs were lower at $668 million compared to $735 million in 2011 mainly due to lower supplemental lease payments and lower maintenance costs. These decreases were partially offset by higher fuel costs in the first nine months of 2012.

The result was a $50 million increase in our share of earnings before taxes.

BPLP distributed $285 million to the partners in the first nine months of 2012; our share was $90 million. BPLP made capital calls of $50 million to the partners in the first nine months of this year; our share was $16 million.

2012 THIRD QUARTER REPORT    25

Our operations and development projects

Uranium – production overview

Production in our uranium segment this quarter was unchanged compared to the third quarter of 2011. For the first nine months, production was down compared to the same period last year mainly due to lower production at Smith Ranch-Highland. SeeUranium 2012 Q3 updates starting on page 28 for more information.

Uranium production

Cameco’s share (million lbs U3O8)	Three months ended September 30							Nine months ended September 30
	2012		2011		change			2012		2011		change
McArthur River/Key Lake		3.8		3.8		—			10.1		10.0		1	%
Rabbit Lake		0.3		0.5		(40	)%		2.1		2.2		(5	)%
Smith Ranch-Highland		0.3		0.3		—			0.8		1.2		(33	)%
Crow Butte		0.2		0.2		—			0.6		0.6		—
Inkai		0.7		0.5		40	%		1.8		1.8		—
Total		5.3		5.3		—			15.4		15.8		(3	)%

Outlook

We have geographically diverse sources of production. Subject to market conditions, our plan is to focus primarily on advancing our brownfield projects and the process to extract uranium from the Talvivaara mine to achieve annual supply of 36 million pounds by 2018.

Cameco’s share of production — annual forecast to 2016

Current forecast (million lbs)	2012		2013		2014		2015		2016
McArthur River/Key Lake		13.5		13.2		13.1		13.1		13.1
Rabbit Lake		3.7		3.7		3.7		3.7		3.4
US ISR		2.0		3.0		3.1		3.7		3.8
Inkai1		2.5		2.9		2.9		2.9		2.9
Cigar Lake		—		0.3		1.9		5.5		7.9
Total share of production		21.7		23.1		24.7		29.1		31.1
Cameco’s share of Inkai’s production on which profits are generated1
Inkai1		2.6		3.0		3.0		3.0		3.0
Total2		21.8		23.2		24.8		29.2		31.2

¹  In 2011, we signed a memorandum of agreement (2011 MOA) with Kazatomprom to increase annual production to 5.2 million pounds (100% basis). Once implemented, we will receive the right to purchase 2.9 million pounds of Inkai’s annual production and receive profits on 3.0 million pounds.

²  We have adjusted the production table to reflect the share of Inkai’s production we will use to calculate our profits under the 2011 MOA, as described in the note above.

26    CAMECO CORPORATION

Our 2012 and future annual production targets for Inkai assume, and we expect:

• Inkai will obtain the necessary government permits and approvals to produce at an annual rate of 5.2 million pounds (100% basis), including an amendment to the resource use contract

• we implement the 2011 MOA

• Inkai will ramp up production to an annual rate of 5.2 million pounds (100% basis)

There is no certainty Inkai will receive these permits or approvals or we will implement the 2011 MOA or that Inkai will be able to ramp up production. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2012 and future annual production targets and we may have to re-categorize some of Inkai’s mineral reserves as resources.

This forecast is forward-looking information. It is based on the assumptions and subject to the material risks discussed on pages 2 and 3, and specifically on the assumptions and risks listed here. Actual production may be significantly different from this forecast.

Assumptions

• we achieve our forecast production for each operation, which requires, among other things, that our mining plans succeed, processing plants and equipment are available and function as designed, we have sufficient tailings capacity and our mineral reserve estimates are reliable

• we obtain or maintain the necessary permits and approvals from government authorities

• our production is not disrupted or reduced as a result of natural phenomena, labour disputes, political risks, blockades or other acts of social or political activism, shortage or lack of supplies critical to production, equipment failures or other development and operation risks

Material risks that could cause actual results to differ materially

• we do not achieve forecast production levels for each operation because of a change in our mining plans, processing plants or equipment are not available or do not function as designed, lack of tailings capacity or for other reasons

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

• natural phenomena, labour disputes, political risks, blockades or other acts of social or political activism, shortage or lack of supplies critical to production, equipment failures or other development and operation risks disrupt or reduce our production

2012 THIRD QUARTER REPORT    27

Uranium 2012 Q3 updates

Operating properties

McArthur River/Key Lake

Production update

Production for the quarter and the first nine months was unchanged compared to the same periods last year. We expect our share of production this year to increase to 13.5 million pounds compared to our previous forecast of 13.1 million pounds U₃O₈.

Production varies from quarter to quarter depending on the sequencing of mining raises and timing of maintenance shutdowns at the mill.

Operations update

At McArthur River, we have started to upgrade our electrical infrastructure to address the future need for increased ventilation and freeze capacity associated with mining new zones and increasing mine production.

At Key Lake, the new steam, oxygen and acid plants are operational. We have started projects to replace the calciner and the electrical substation.

We continue to make excellent progress in flattening the slope of the Deilmann tailings management facility pitwalls at Key Lake. The project will reduce the risk of loss of tailings capacity due to pitwall sloughing.

We are continuing to advance work on the environmental assessment for the Key Lake extension project. We have received comments from the regulators on our draft environmental impact statement and are working to address the questions and issues they have raised. We plan to submit the final environmental impact statement in 2013.

In cooperation with several uranium industry partners in Saskatchewan, we have been working on a plan with the provincial government to connect our McArthur River and Cigar Lake mine sites by completing Highway 914 in the Athabasca Basin. This crucial connection will expand access to milling infrastructure across the northern part of the province, enhance transportation efficiency and offer an alternate route in and out of northern Saskatchewan. The Government of Saskatchewan has agreed to fund half of the cost of the final road with the industry partners sharing the remaining half.

Technical report

We are updating the February 2009 McArthur River technical report to reflect further advancements and changes to the McArthur River operations since that time. We plan to file the updated technical report during the fourth quarter. The highlights of the technical report are:

• a 19% increase in our share of the mineral reserves estimate from 226.2 million pounds at December 31, 2011 to 269.1 million pounds as of August 31, 2012 due to a 22% addition in tonnage and a slight decrease in the estimated average grade. SeeMcArthur River mineral reserves and mineral resources estimates table below for more details.

• a decrease in the estimated average cash operating cost to about $19.23 per pound over the life of the mine from about $19.69 per pound estimated in 2009, despite the escalating costs in the industry. See table titledMcArthur River/Key Lake life of mine production, average unit operating costs and capital cost forecasts below for more details.

• a production rate increase to 22 million pounds per year scheduled for 2018, subject to regulatory approval

• a mine life of at least 22 years, based on the planned production schedule

• our share of capital costs at McArthur River and Key Lake to 2034 is estimated at $2.5 billion compared to $1.4 billion in the previous report. More than 40% of this increase is related to the addition of more than 85 million pounds of new production since the 2009 technical report, and about 15% relates to expenditures required to allow production at a higher rate such as additional ventilation including the sinking of a fourth shaft. The

28    CAMECO CORPORATION

remainder of the increase is related to expanding the infrastructure to support ongoing and expanded operations, and general cost escalation. We expect these changes will generate significant cash flows for years to come.

McArthur River mineral reserves and mineral resources estimates

(tonnes in thousands, pounds in millions)

(as at August 31, 2012)	Tonnes		Grade % U3O8		Content (lbs U3O8)		Cameco’s share of content (lbs U3O8)
Reserves
Proven		384.4		23.81		201.8		140.8
Probable		677.8		12.30		183.7		128.3
Total proven and probable mineral reserves		1,062.2		16.46		385.5		269.1
Resources
Measured		68.6		5.53		8.4		5.8
Indicated		15.5		9.97		3.4		2.4
Total measured and indicated mineral resources		84.1		6.35		11.8		8.2
Inferred mineral resources		325.0		7.86		56.3		39.3

Notes:

• Mineral reserves and mineral resources are reported separately. Mineral resources do not include amounts identified as mineral reserves. Reported mineral reserves have not been adjusted for estimated mill recovery of 98.7%.

• Our share of total mineral reserves and total mineral resources is 69.805%.

• Inferred mineral resources have a great amount of uncertainty as to their existence and whether they can be mined legally or economically. It cannot be assumed that all or any part of the inferred mineral resources will be upgraded to a higher category.

• Mineral resources are estimated at a minimum mineralized thickness of 1.0 metre and a minimum grade of 0.1% to 0.5% U₃O₈ assuming extraction by underground mining methods. Mineral reserves have been estimated at a cut-off grade of 0.77% U₃O₈.

• The geological model employed for McArthur River involves geological interpretations on section and plan derived from surface and underground drillhole information.

• Mineral reserves include allowances for estimated dilution (20%) from backfill and mineralized waste mined and mining recovery (97.5%). Mineral resources do not include such allowances.

• Mineral reserves are estimated using the raisebore, boxhole and blasthole stope mining methods combined with freeze curtains.

• Mineral resources are estimated using a cross-sectional method and 3-dimensional block models. Mineral reserves are estimated using 3-dimensional block models.

• An average uranium price assumption of $61US/lb U₃O₈ and a fixed exchange rate of $1.00 US=$1.00 Cdn was used to estimate mineral reserves. The McArthur River mineral reserves are not significantly sensitive to variances in the uranium price of plus or minus $20 provided that annual production remains above 10 million pounds U₃O₈. The price assumption is based on independent industry and analyst estimates of spot prices and the corresponding long-term prices and reflects our committed and uncommitted sales volumes. For committed sales volumes, the spot and term price assumptions were applied in accordance with the terms of the agreements. For uncommitted sales volumes the same price assumptions were applied using a spot-to-term price ratio of 60-40.

2012 THIRD QUARTER REPORT    29

• No known metallurgical, environmental, permitting, legal, title, taxation, socio-economic, political, marketing or other issues are expected to materially affect the above estimates of mineral resources and mineral reserves.

• Mineral resources that are not mineral reserves do not have demonstrated economic viability. Totals may not add due to rounding.

McArthur River/Key Lake life of mine production, average unit operating costs and capital cost forecasts

(as per technical report)

(as at January 1, 2012)	2012		2013		2014		2015		2016		2017		2018		2019
Production (million lbs)		13.5		13.2		13.1		13.1		13.1		13.1		15.4		15.4
Average operating cost ($Cdn/lb U3O8)		16.74		17.26		17.52		17.37		17.64		17.20		15.01		15.37
Total capital costs ($ millions)		189.3		235.0		285.8		236.8		214.2		151.8		168.7		134.2

(as at January 1, 2012)	2020		2021		2022		2023		2024		2025		2026		2027
Production (million lbs)		15.4		15.4		14.9		14.9		14.9		14.9		14.7		13.5
Average operating cost ($Cdn/lb U3O8)		15.28		15.28		15.91		15.99		16.09		17.25		17.47		18.75
Total capital costs ($ millions)		107.5		109.7		89.6		67.8		65.9		67.5		52.2		58.2

(as at January 1, 2012)	2028		2029		2030		2031		2032		2033		2034		Total
Production (million lbs)		13.3		7.2		7.2		7.1		7.1		4.4		4.5		279.1
Average operating cost ($Cdn/lb U3O8)		18.74		31.90		31.23		31.68		31.65		48.29		47.97		19.23
Total capital costs ($ millions)		55.0		40.2		40.8		36.2		28.5		17.6		11.9		2,464.4

Rabbit Lake

Production update

Production remains on track for the year. To ensure the most efficient operation of the mill throughout the year, we continually manage ore supply and, therefore, experience large variations in mill production from quarter to quarter.

Operations update

We completed the scheduled mill maintenance shutdown this quarter. A short delay in restarting the mill resulted in slightly lower production compared to the third quarter of 2011, although we are maintaining our forecast production of 3.7 million pounds for the year.

We completed our surface exploration drilling program, which returned positive results near the existing mining operations.

Smith Ranch-Highland and Crow Butte

Production update

At our US operations, production for the quarter was unchanged compared to the third quarter of 2011. Production for the first nine months was 33% lower compared to the same period last year due to lower production from Smith Ranch-Highland in the first half of the year.

We have decreased our production forecast for the year by 17% to 2.0 million pounds based on the outlook for the approval of new mine units. Our ability to bring new wellfields into production at Smith Ranch-Highland continues to be affected by the lengthened review process to obtain regulatory approvals.

30    CAMECO CORPORATION

Operations update

We received approval to produce from mine unit K-North at Smith Ranch-Highland and continue to seek regulatory approvals to proceed with the rest of our expansion plans.

Inkai

Production update

Production was 40% higher for the quarter and unchanged for the first nine months compared to the same periods last year. We continue to bring on additional wellfields to maintain some new, typically higher grade, wellfields in the production mix. Production at the Inkai operation steadily improved over the quarter and the facility is now operating at design capacity.

Operations update

We continue to pursue government approval of an amendment to the resource use contract in order to implement the production increase from blocks 1 and 2 to 5.2 million pounds of U₃O₈ (100% basis).

Delineation drilling at block 3 continues and construction of the test leach facility is underway.

On October 31, 2012, our board of directors approved a binding memorandum of agreement (2012 MOA) with our joint venture partner Kazatomprom setting out a framework to:

• increase Inkai’s annual production from blocks 1 and 2 to 10.4 million pounds of uranium concentrate (our share 5.2 million pounds) and sustain it at that level

• extend the term of Inkai’s resource use contract through 2045

Kazatomprom is pursuing a strategic objective to develop uranium processing capacity in Kazakhstan to complement its leading uranium mining operations. The 2012 MOA builds on the non-binding memorandum of understanding signed in 2007 to co-operate on the development of uranium conversion capacity, with Kazatomprom’s primary focus now being on uranium refining rather than uranium conversion.

The 2012 MOA strengthens our partnership with Kazatomprom and includes a number of connected provisions relating to the increase of Inkai’s annual production and extension to the term of Inkai’s resource use contract. Under the terms of the 2012 MOA, we agree to:

• adjust our ownership interests in Inkai to 50% on an overall basis after achieving the production increase

• make two milestone payments of $34 million (US) each – the first after Inkai receives all necessary government approvals to increase uranium production to 10.4 million pounds (100%) annually through 2045, and the second after the increased production target is achieved

• pay to Kazatomprom a royalty of $5 (US) per pound of uranium concentrate on our share of production above 2.6 million pounds annually from Inkai once Inkai obtains all approvals required for the production increase to 10.4 million pounds (100% basis)

• participate in the construction and operation of a uranium refinery in Kazakhstan with capacity to produce 6,000 tonnes of uranium (tU) as UO₃ annually, where we will own one third of the refinery and the remaining two thirds will be owned by Kazatomprom, with construction to begin by 2018

• provide Kazatomprom with a five-year option to license our proprietary uranium conversion technology for purposes of constructing and operating a UF₆ conversion facility in Kazakhstan

• negotiate with Kazatomprom toward a conversion services agreement for up to 4,000 tU of conversion services annually and/or, for a three-year period, provide an opportunity for Kazatomprom to acquire a one-third interest in our conversion facility in Canada

Under the 2012 MOA, the first steps will be to complete a feasibility study for the production increase, and a prefeasibility study for the uranium refinery. We agree to work with Kazatomprom to pace investments for increasing uranium production to match progress on the transfer of our uranium refining technology and construction of the uranium refinery in Kazakhstan, subject to market conditions.

2012 THIRD QUARTER REPORT    31

Implementation of the 2012 MOA is subject to:

• further agreements on a number of issues including agreements governing the ownership, construction and operation of the uranium refinery in Kazakhstan

• approval by Kazatomprom’s board of directors

• the receipt of all necessary Canadian and Kazakhstan governmental approvals including all licences and permits required to allow the transfer and licensing of our uranium refining technology

Development project

Cigar Lake

We continued to make solid progress at Cigar Lake this quarter.

We have assembled the first jet boring system unit underground and moved it to a production tunnel where we:

• have begun preliminary commissioning

• will begin systems testing

• will prepare to test in waste rock.

In shaft 2 we are installing infrastructure, including a concrete ventilation partition, electrical cable, water services, ore slurry pipes and hoist systems.

We will focus on carrying out the remainder of our 2012 plans and implementing the strategies we outlined in our annual MD&A. We continue to expect first commissioning in ore in mid-2013 and the first packaged pounds in the fourth quarter of 2013.

Cigar Lake is a key part of our plan to increase annual uranium supply, and we are committed to bringing this valuable asset safely into production.

Projects under evaluation

Millennium

We have received comments from the regulators on our draft environmental impact statement and are working to address the questions and issues they have raised. We plan to submit the final environmental impact statement in 2013.

We completed the summer exploration drill program and successfully identified additional mineralization at the unconformity.

We will advance this project at a pace aligned with market opportunities and economic circumstances.

Kintyre

On October 11, 2012, we announced the successful signing of a mine development agreement with the Martu – a key activity in our project planning.

Based on our review of the current market environment, we will complete the value engineering and the environmental permitting in order to maintain the ability to proceed with the project should the market factors improve the economics. However, we have decided not to proceed with the detailed feasibility study at this time.

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Fuel services 2012 Q3 updates

Port Hope conversion services

Cameco Fuel Manufacturing Inc.

Springfields Fuels Ltd. (SFL)

Production update

Fuel services produced 2.1 million kgU in the third quarter, 25% lower than the same period last year. Production for the first nine months of the year was 10.9 million kgU, 6% lower than the same period last year. As a result of the planned reduction in production, results will remain lower than comparable periods in 2011; however, production remains on track for the year.

Qualified persons

The technical and scientific information discussed in this MD&A for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) was approved by the following individuals who are qualified persons for the purposes of

NI 43-101:

McArthur River/Key Lake

• David Bronkhorst, vice-president, Saskatchewan mining south, Cameco

• Alain Mainville, director, mineral resources management, Cameco

• Les Yesnik, general manager, Key Lake, Cameco

• Gregory Murdock, technical manager, McArthur River, Cameco

Cigar Lake

• Grant Goddard, vice-president, Saskatchewan mining north, Cameco

Inkai

• Dave Neuburger, vice-president, international mining, Cameco

Additional information

Related party transactions

We buy significant amounts of goods and services for our Saskatchewan mining operations from northern Saskatchewan suppliers to support economic development in the region. One of these suppliers is Points Athabasca Contracting Ltd. (PACL). In the first nine months of 2012, we paid PACL $32 million for construction and contracting services (2011—$47 million). These transactions were carried out in the normal course of business. A member of Cameco’s board of directors is the president of PACL.

Critical accounting estimates

In our 2011 annual MD&A, we have identified the critical accounting estimates that reflect the more significant judgments used in the preparation of our financial statements. Please refer to note 2 of our interim financial statements for a detailed description of our application of estimates and judgment in the preparation of our financial information.

Controls and procedures

As of September 30, 2012, 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.

2012 THIRD QUARTER REPORT    33

Based upon that evaluation and as of September 30, 2012, 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, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

New accounting pronouncements

New standards and interpretations not yet adopted

We have not yet adopted the standards and amendments to existing standards that have been issued. The standards and amendments, unless otherwise stated, are effective for periods beginning on or after January 1, 2013. Please refer to our 2011 annual MD&A for a brief description of each accounting pronouncement. We are assessing the impact of the following standards and amendments on our financial statements:

• IFRS 7, Financial Instruments: Disclosures

• IFRS 9, Financial Instruments

• IFRS 10, Consolidated Financial Statements

• IFRS 11, Joint Arrangements

• IFRS 12, Disclosure of Interests in Other Entities

• IFRS 13, Fair Value Measurement

• IAS 1, Presentation of Financial Statements

• IAS 19, Employee Benefits

• IAS 32, Financial Instruments: Presentation (January 1, 2014)

34    CAMECO CORPORATION