Exhibit 1

Management’s discussion

and analysis

February 11, 2013

This management‘s discussion and analysis (MD&A) includes information that will help you understand management‘s perspective of our audited consolidated financial statements (financial statements) and notes for the year ended December 31, 2012. This information is based on what we knew on February 8, 2013.

We encourage you to read our financial statements and notes as you review this MD&A. You can find more information about Cameco, including our 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.

WHAT’S INSIDE

5 2012 highlights

8 The nuclear fuel cycle

9 About Cameco

12 The nuclear industry today

15 The long-term view

18 Our strategy

29 Measuring our results

32 Financial results

61 Our operations and development projects

98 Mineral reserves and resources

104 Additional information

Throughout this document, the terms we, us, our and Cameco mean Cameco Corporation and its subsidiaries; however it does not include NUKEM Gmbh (NUKEM), unless otherwise indicated.

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

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, future financial and operating performance, or other things that have not yet taken place, we are making statements considered to be forward-looking information or forward-looking statements under Canadian and United States securities laws. We refer to them in this MD&A as forward-looking information.

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

• It typically includes words and phrases about the future, such as: believe, estimate, anticipate, expect, plan, intend, predict, goal, target, project, potential, strategy and outlook (see examples below).

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

• It is based on a number of material assumptions, including those we have listed on page 4, 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 3. We recommend you also review our annual information form, 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 may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws.

Examples of forward-looking information in this MD&A

• our expectations about 2013 and future global uranium supply, consumption, demand, long-term contracting volumes, number of operable reactors and nuclear generating capacity, including the discussion on the expected impact resulting from the March 2011 nuclear incident in Japan

• our expectations for spot prices in 2013

• our strategy for increasing annual supply to 36 million pounds by 2018, including the expected sources of such supply and development projects in connection therewith

• our expectation that existing cash balances and operating cash flows will meet anticipated 2013 capital requirements without the need for any significant additional funding

• our expectations regarding uranium demand in the near term

• our 2013 objectives

• the outlook for each of our operating segments for 2013, and our consolidated outlook for the year

• our outlook for the first quarter of 2013

• our expectation that we will continue to invest in expanding our production capacity at our existing mines and advancing projects as we pursue our growth strategy

• our expectation that cash balances will decline as we use the funds in our business and pursue our growth plans

• our expectations for 2013, 2014 and 2015 capital expenditures

• our expectation that our operating and investment activities in 2013 will not be constrained by the financial covenants in our unsecured revolving credit facility

• our uranium price sensitivity analysis

• forecast production at our uranium operations from 2013 to 2017

• the likely terms and volumes to be covered by long-term delivery contracts that we enter into in 2013 and in future years

• our expectations about the purchase volumes and prices to be realized under the Russian HEU commercial agreement in 2013, as well as our expectations and strategy regarding maintaining sales volumes when the Russian HEU commercial agreement ends

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• our expectations about 2013 global consumption of conversion services and production at our fuel services operations

• future royalty and tax payments and rates

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

• our expectations regarding Cigar Lake

• our mineral reserve and resource estimates

• our expectations regarding the cash flows, profit margins, uranium deliveries, sales, revenues, costs, tax rates and profitability recognized by NUKEM in 2013 and in the future

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, or we are unsuccessful in our dispute with tax authorities

• 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, 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 and conversion suppliers fail to fulfill delivery commitments

• our Cigar Lake development, mining or production plans are delayed or do not succeed, including as a result of any difficulties encountered with the jet boring mining method or our inability to acquire any of the required jet boring equipment

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

• our operations are disrupted due to problems with our own or our customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, lack of tailings capacity, labour shortages, labour relations issues (including an inability to renew agreements with unionized employees at McArthur River, Key Lake or the Port Hope Conversion facility), strikes or lockouts, underground floods, cave ins, ground movements, tailings dam failures, transportation disruptions or accidents, or other development and operating risks

MANAGEMENT’S DISCUSSION AND ANALYSIS 3

• NUKEM’s actual uranium sales volume, cash flows and earnings in 2013 and in the future are lower than expected due to losses in connection with spot market purchases, counterparty default on payment or other obligations, counterparty insolvency or other risks

• departure of key personnel at NUKEM could have an adverse effect on continuing operations

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 adversely affected 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 expenditure expectations

• our expectations regarding spot prices and realized prices for uranium, and other factors discussed on pages 48 and 49, Price sensitivity analysis: uranium

• our expectations regarding tax rates and payments, the outcome of the dispute with tax authorities, 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

• our Cigar Lake development, mining and production plans succeed, including the success of the jet boring mining method at Cigar Lake and that we will be able to obtain the additional jet boring system units we require on schedule

• 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, social or political activism, equipment breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues (including an inability to renew agreements with unionized employees at McArthur River, Key Lake or the Port Hope Conversion facility), 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

• NUKEM’s actual uranium sales volume, cash flows and earnings in 2013 and in the future will be consistent with our expectations

• key personnel will remain with NUKEM

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2012 highlights

The long-term outlook for growth in the nuclear industry remains very strong, with 64 reactors under construction at the beginning of 2013, and an average annual increase in uranium demand expected to be around 3% over the next decade. However, the near-term challenges have persisted for longer than anticipated due to the lingering effects of the events in Japan, as well as global economic slowdown. As a result, in 2012, we re-examined our growth plans and adjusted them to better match current market conditions. We decided to focus primarily on advancing those projects with the most near-term certainty, while pursuing our other projects at a measured pace in order to maintain the ability to respond should market conditions improve. We expect this approach will result in our achieving 36 million pounds of annual supply by 2018, and allow us to spread our capital spend over a longer period of time, improving our near-term financial performance.

In spite of the challenging market environment, we demonstrated our strengths again in 2012, exceeding our production target and delivering on our financial guidance.

Strong financial performance

Our financial results remained strong in 2012:

• annual revenue of $2.3 billion

• annual gross profit of $723 million from our nuclear business

• annual revenue of $1.5 billion from our uranium segment

• annual average realized price of $47.61 per pound ($47.62 US per pound) in our uranium segment

Net earnings attributable to our equity holders (net earnings) in 2012 were $266 million compared to $450 million in 2011. This $184 million decline in net earnings was the result of:

• a $168 million write-down of our investment in the Kintyre deposit, required due to the weakening of the uranium market since the asset was purchased in 2008, no increase in mineral resources in 2012 and the decision not to proceed with the feasibility study in 2012

• lower earnings in our uranium business

• stronger results in our electricity segment.

HIGHLIGHTS DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED)			2012		2011		CHANGE
Revenue				2,321		2,384		(3	)%
Gross Profit				723		776		(7	)%
Net earnings attributable to equity holders				266		450		(41	)%
$ per common share (diluted)				0.67		1.14		(41	)%
Adjusted net earnings (non-IFRS, see page 34)				447		509		(12	)%
$ per common share (adjusted and diluted)				1.13		1.29		(12	)%
Cash provided by operations (after working capital changes)				644		745		(14	)%
Average realized prices	Uranium	$US/lb		47.62		49.17		(3	)%
		$Cdn/lb		47.61		49.18		(3	)%
	Fuel services	$Cdn/kgU		17.24		16.71		3	%
	Electricity	$Cdn/MWh		55		54		2	%

MANAGEMENT’S DISCUSSION AND ANALYSIS 5

Solid progress in our uranium segment this year

In our uranium segment this year, production was 1% higher than the guidance we provided in our 2012 third quarter MD&A. We had a number of successes at our mining operations, development projects and projects under evaluation. Key highlights:

• realized benefits of production flexibility provisions in our McArthur River/Key Lake licences, exceeding our production target by 1%

• completed a technical report for McArthur River which included a 19% increase in mineral reserves

• completed remediation of the underground mine and sinking of shaft 2 at Cigar Lake

• assembled the first jet boring system unit underground at Cigar Lake and began preliminary commissioning and testing

• purchased AREVA Resources Canada Inc.’s 27.94% interest in the Millennium project to acquire majority ownership interest of 69.9%

• the Finnish government granted Talvivaara, a company from which we have the right to buy uranium produced as a by-product, a licence to extract uranium as a by-product from the Sotkamo nickel mine

• acquired the Yeelirrie uranium project in Western Australia from BHP Billiton Yeelirrie Development Company Pty Ltd.

• signed a mine development agreement with the Martu concerning our Kintyre project

• entered into a binding memorandum of agreement with our joint venture partner Kazatomprom, setting out the framework to increase annual production at Inkai to 10.4 million pounds (100% basis), to extend the term of Inkai’s resource use contract through 2045, and to co-operate on the development of uranium conversion capacity, with the primary focus on uranium refining rather than uranium conversion

We also continued to advance our exploration activities, spending $10 million on four brownfield exploration projects, and $24 million for project evaluation at Kintyre and Cigar Lake. We spent about $45 million on regional exploration programs, mostly in Saskatchewan, followed by Australia, northern Canada, Asia and South America.

Updates on our other segments

In our fuel services segment, we decreased production due to unfavourable market conditions for UF₆. We signed a new three-year collective agreement with about 120 unionized employees at our fuel manufacturing operations in Port Hope and Cobourg, Ontario.

In our electricity segment, Bruce Power Limited Partnership (BPLP) generated 26.8 terawatt hours (TWh) of electricity, at a capacity factor of 94%. Our share of earnings before taxes was $175 million, a 90% increase compared to 2011.

We entered into an agreement with Advent International to purchase NUKEM Energy GmbH, one of the world’s leading traders and brokers of nuclear fuel products and services, which was completed in January, 2013.

Our investment in Global Laser Enrichment (GLE) continues to progress. GLE is continuing its testing activities and engineering design work for a commercial facility. The US Nuclear Regulatory Commission approved GLE’s application for a commercial facility construction and operating licence.

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HIGHLIGHTS		2012		2011		CHANGE
Uranium	Production volume (million lbs)		21.9		22.4		(2	)%
	Sales volume (million lbs)		32.5		32.9		(1	)%
	Revenue ($ millions)		1,546		1,616		(4	)%
	Gross profit ($ millions)		504		632		(20	)%
Fuel services	Production volume (million kgU)		14.2		14.7		(3	)%
	Sales volume (million kgU)		16.1		18.3		(12	)%
	Revenue ($ millions)		277		305		(9	)%
	Gross profit ($ millions)		42		54		(22	)%
Electricity	Output (100%) (TWh)		26.8		24.9		8	%
	Revenue (100%)		1,487		1,354		10	%
	Our share of earnings before taxes ($ millions)		175		92		90	%

SHARES AND STOCK OPTIONS OUTSTANDING

At February 7, 2013, we had:

• 395,351,354 common shares and one Class B share outstanding

• 9,505,753 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 7

The nuclear fuel cycle

1 Mining

Once an orebody is discovered and defined by exploration, there are three common ways to mine uranium, depending on the depth of the orebody and the deposit’s geological characteristics:

• Open pit mining is used if the ore is near the surface. The ore is usually mined using drilling and blasting.

• Underground mining is used if the ore is too deep to make open pit mining economical. Tunnels and shafts provide access to the ore.

• In situ recovery (ISR) does not require large scale excavation. Instead, holes are drilled into the ore and a solution is used to dissolve the uranium. The solution is pumped to the surface where the uranium is recovered.

1 Milling

Ore from open pit and underground mines is processed to extract the uranium and package it as a powder typically referred to as uranium concentrates (U₃O₈) or yellowcake. The leftover processed rock and other solid waste (tailings) is placed in an engineered tailings facility.

2 Refining

Refining removes the impurities from the uranium concentrate and changes its chemical form to uranium trioxide (UO₃).

3 Conversion

For light water reactors, the UO₃ is converted to uranium hexafluoride (UF₆) gas to prepare it for enrichment. For heavy water reactors like the Candu reactor, the UO₃ is converted into powdered uranium dioxide (UO₂).

4 Enrichment

Uranium is made up of two main isotopes: U-238 and U-235. Only U-235 atoms, which make up 0.7% of natural uranium, are involved in the nuclear reaction (fission). Most of the world’s commercial nuclear reactors require uranium that has an enriched level of U-235 atoms.

The enrichment process increases the concentration of U-235 to between 3% and 5% by separating U-235 atoms from the U-238. Enriched UF₆ gas is then converted to powdered UO₂.

5 Fuel manufacturing

Natural or enriched UO₂ is pressed into pellets, which are baked at a high temperature. These are packed into zircaloy or stainless steel tubes, sealed and then assembled into fuel bundles.

6 Generation

Nuclear reactors are used to generate electricity.

U-235 atoms in the reactor fuel fission, creating heat that generates steam to drive turbines. The fuel bundles in the reactor need to be replaced as the U-235 atoms are depleted, typically after one or two years depending upon the reactor type. The used–or spent–fuel is stored or reprocessed.

Spent fuel management

The majority of spent fuel is safely stored at the reactor site. A small amount of spent fuel is reprocessed. The reprocessed fuel is used in some European and Japanese reactors.

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About Cameco

Our head office is in Saskatoon, Saskatchewan. We are one of the world’s largest uranium producers, with uranium assets on three continents. Nuclear energy plants around the world use our uranium products to generate one of the cleanest sources of electricity available today. Our operations and investments span the nuclear fuel cycle, from exploration to electricity generation.

Strengths

We are a pure-play nuclear investment with a proven track record and the strengths to take advantage of the world’s rising demand for safe, clean and reliable energy.

With our extraordinary assets, contract portfolio, employee expertise, comprehensive industry knowledge and financial strength, we are confident in our ability to continue to grow and increase shareholder value.

Business segments

URANIUM
We are one of the world’s largest uranium producers, and in 2012 accounted for about 14% of the world’s production. We have controlling ownership of the world’s largest high-grade reserves, with ore grades up to 100 times the world average, and low-cost operations. Product • uranium concentrates (U3O8 ) Mineral reserves and resources Mineral reserves •       approximately 465 million pounds proven and probable Mineral  resources •       approximately 244 million pounds measured and indicated and 287 million pounds inferred Global exploration •       focused on four continents •       approximately 3.7 million hectares of land	Operating properties •       McArthur River and Key Lake, Saskatchewan •       Rabbit Lake, Saskatchewan •       Smith Ranch-Highland, Wyoming •       Crow Butte, Nebraska •       Inkai, Kazakhstan Development project •       Cigar Lake, Saskatchewan Projects under evaluation •       Inkai blocks 1 and 2 production increase, Kazakhstan •       Inkai block 3, Kazakhstan •       Millennium, Saskatchewan •       Yeelirrie, Australia •       Kintyre, Australia
FUEL SERVICES
We are an integrated uranium fuel supplier, offering refining, conversion and fuel manufacturing services. Products •       uranium trioxide (UO3) •       uranium hexafluoride (UF6)          (control about 25% of world conversion capacity) •       uranium dioxide (UO2)          (the world’s only commercial supplier of natural UO2) •       fuel bundles, reactor components and monitoring equipment used by Candu reactors	Operations •       Blind River refinery, Ontario          (refines uranium concentrates to UO3) •       Port Hope conversion facility, Ontario          (converts UO3 to UF6 or UO2) •       Cameco Fuel Manufacturing Inc., Ontario          (manufactures fuel bundles and reactor components) •       a toll conversion agreement with Springfields Fuels Ltd. (SFL), Lancashire, United Kingdom (UK)          (to convert UO3 to UF6 – expires in 2016) We also have a 24% interest in Global Laser Enrichment (GLE) in North Carolina, with General Electric (51%) and Hitachi Ltd. (25%). GLE is testing a third-generation technology that, if successful, will use lasers to commercially enrich uranium.
NUKEM
Our ownership of NUKEM GmbH (NUKEM) provides us with access to one of the world’s key traders of uranium and uranium-related products. We acquired NUKEM in January, 2013.	Activity •       physical trading of uranium concentrates, conversion and enrichment services through back to back purchase and sales transactions •       recovery of natural and enriched non-standard uranium from western facilities and other sources

MANAGEMENT’S DISCUSSION AND ANALYSIS 9

ELECTRICITY

We generate clean electricity through our 31.6% interest in the Bruce Power Limited Partnership (BPLP), which operates four nuclear reactors at the Bruce B generating station in southern Ontario.

Capacity

• 3,260 megawatts (MW) (100% basis)

(about 15% of Ontario’s electricity)

We also have agreements to manage the procurement of fuel and fuel services for BPLP, including:

• uranium concentrates

• conversion services

• fuel fabrication services

KEY MARKET FACTS

The 2012 World Energy Outlook predicts that by 2035 electricity consumption will have grown by about 70% from current levels, driven mainly by growth in the developing world as it seeks to diversify sources of energy and provide security of supply.

• At the start of 2013, there were 433 operable commercial nuclear power reactors in 31 countries, and by 2022, we expect that to grow to 524 reactors.

• At the start of 2013, there were 64 reactors under construction in 14 countries, and dozens more planned to begin operation by 2022.

• Most of this new build is being driven by rapidly developing countries like China and India, which have severe energy deficits and want clean sources of electricity to improve their environment and sustain economic growth.

• Over the next decade, we expect demand for uranium to grow by an average of 3% per year and to meet global demand, we expect about two-thirds of uranium supply will come from mines that are currently in operation, about 15% from finite sources of secondary supply (mainly Russian highly enriched uranium (HEU), government inventories and limited recycling), and about 20% will have to come from new sources of supply.

• With uranium assets on three continents, including high-grade reserves and low-cost mining operations in Canada, and investments that cover the nuclear fuel cycle—we are ideally positioned to benefit from the world’s growing need for clean, reliable energy.

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GLOBAL PRESENCE

MANAGEMENT’S DISCUSSION AND ANALYSIS 11

The nuclear energy industry today

In last year’s annual review of the uranium market, we indicated that the near-term environment for the industry was challenging, but that the long-term outlook remained very positive. We believe this continues to be the case today.

There was little improvement in 2012 over 2011 due to the lingering effects of the events in Japan, as well as global economic slowdown. However, we started to see some clarity on issues that have been overhanging the market. The most significant of these was the establishment in Japan of the Nuclear Regulatory Authority (NRA), which is currently drafting new safety standards for the nuclear industry in that country, against which reactor restarts will be evaluated. The NRA indicated that this process would likely take until mid-2013. While this means that reactor restarts will take longer than we had previously thought, we believe that the NRA brings important stability to the nuclear regulatory environment in Japan, and welcome the clarity it has already brought to the issue of reactor restarts.

We believe the election of the Liberal Democratic Party (LDP) in Japan will be similarly positive for the nuclear industry. Though it remains to be seen what kind of energy policy will emerge from the newly elected government, the LDP has been positively disposed towards nuclear in the past, and has been clear that rebuilding Japan’s economy is its main priority, in which the nuclear industry plays a large role.

Later in 2012, China lifted a temporary moratorium on new reactor construction and has since started construction on four reactors. The resumption of reactor construction in China is clearly a positive signal for the market.

Beyond Japan and China, some other countries made changes to their nuclear programs, including announcements of older reactor retirements from Canada, France and Belgium. India also revised its 2020 nuclear target down from 20 to 14.6 gigawatts. These changes, combined with slower than expected restarts in Japan, the temporary pause in China new-build approvals, and slower economic growth worldwide, caused us to re-examine our reactor forecast at the end of 2012. While the market continues to evolve, our current estimates project nuclear generating capacity to reach about 510 gigawatts by 2022 from today’s 392 gigawatts, which represents average annual growth of 3%. Of this expected growth, approximately 64 new reactors with 64 gigawatts of generating capacity are under construction today.

Reactor retirements and delays in both restarts and new construction have had an effect on demand and the uranium price in 2012. There has been concern that excess inventories resulting from reduced requirements, deferrals and/or cancellations of deliveries under sales contracts could be introduced to the market. In 2012, any excess inventories have been responsibly managed between suppliers and customers, but the situation has caused market participants to be discretionary in their purchases and the uranium price to remain depressed. This remains the case at the beginning of 2013, but we believe the clearing of excess inventories, resumption of restarts in Japan and new-build around the world, in addition to promising supply-demand fundamentals, will lead to improved market conditions. We also anticipate utilities will be ramping up contracting activities well in advance of their requirements becoming uncovered around 2016.

The other side of the equation is supply, which saw a great deal of destruction and deferral in 2012 as the uranium spot price remained at a level well below where new projects are economic. A number of uranium producers decreased their production growth plans, ourselves included when we announced the adjustment to our growth plans from 40 million pounds annual production down to 36 million pounds of annual supply by 2018. Details on our strategy are available on page 18.

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These challenges to primary supply occur while secondary supply is decreasing as a result of the end of the Russian Highly Enriched Uranium (HEU) commercial agreement in 2013, and while steady demand growth continues – with an expectation that it will reach about 3% per year.

So, although the supply-demand outlook continues to evolve, nuclear remains an important part of the global energy mix and it is clear that new uranium supply will be needed. Though some of the future supply gap could be filled by additions to secondary supplies, the majority will need to come from new mines and expansions to existing mines, which we expect will bring the economics of new production to bear on the market. You can read more about our outlook on future supply and demand in The long-term view on page15.

Industry prices

In 2012, the spot price declined from $52 (US) per pound to the low $42 (US) per pound range. Utilities continue to be well covered under existing contracts. Given the current uncertainties in the market, we expect utilities and other market participants will continue to be opportunistic in their buying. We expect uranium demand in the near- to medium-term to remain somewhat discretionary, and prices to be relatively stable in 2013.

	2012		2011		CHANGE
Uranium ($US/lb U3O8 ) 1
Average spot market price		48.40		56.36		(14	)%
Average long-term price		60.13		66.79		(10	)%
Fuel services ($US/kgU as UF6)1
Average spot market price
• North America
• Europe
Average long-term price		7.99		10.61		(25	)%
• North America		8.56		10.61		(19	)%
• Europe		16.75		16.09		4	%
Note: the industry does not publish UO2 prices.		17.25		16.42		5	%
Electricity ($/MWh)
Average Ontario electricity spot price		23		30		(23	)%

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 13

World consumption and production

We estimate global uranium consumption in 2012 was about 165 million pounds and production was 152 million pounds.

We expect global uranium consumption to increase to about 170 million pounds in 2013, and global production to be approximately 158 million pounds. Secondary supplies should continue to bridge the gap.

By 2022, we expect world uranium consumption to be about 220 million pounds per year, representing average annual growth of about 3%. These consumption estimates exclude strategic inventory building that we expect will occur in growth regions.

We expect existing primary production to decrease over the next decade reaching 125 million pounds by 2022 which highlights the need for new primary supply.

We expect world consumption for UF₆ and natural UO₂ conversion services to increase by about 3% in 2013.

Contract volumes

The Ux estimate for global spot market sales in 2012 is about 43 million pounds, significantly lower than in previous years. Utilities were responsible for over 45% of the purchases. Traders and financial players were also participants, taking advantage of the lower spot prices to make opportunistic purchases.

At the start of 2012, we estimated long-term contracting volumes for the year to be between 80 million and 100 million pounds, though they ended the year at about 194 million pounds. The higher than expected contracting can be attributed to a small number of large volume deals. We estimate long-term contracting volumes in 2013 will be between 75 million and 100 million pounds, depending on supply, market expectations and market prices.

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The long-term view

We remain confident in the long-term fundamentals of the nuclear industry, despite the near- to medium-term challenges. Our industry is driven by demand for energy, which continues to grow as a result of continued increases in world population and industrial development. The 2012 World Energy Outlook predicts that by 2035 electricity consumption will have grown by about 70% from current levels. Most of this energy will be used by developing (non-OECD) countries as their populations and standards of living increase.

New reactor outlook

Within this context, most countries are pursuing a diversified approach to energy growth, with an emphasis on energy security and clean energy. Nuclear power can generate baseload electricity with no toxic air pollutants, carbon dioxide (CO₂) or other greenhouse gas emissions. It has the capacity to produce enough electricity on a global scale to meet the world’s growing needs, and while it is not the only solution, it is an affordable and sustainable source of safe, clean and reliable energy. As a result, we expect nuclear energy to remain an important part of the energy mix.

This is evident in the growth in reactor construction we expect over the next 10 years. There are 433 reactors operable today with a total generating capacity of 392 gigawatts. We expect nuclear generating capacity to reach about 510 gigawatts (524 reactors) by 2022, which represents average annual growth of 3%. Of this growth, approximately 64 reactors with 64 gigawatts of generating capacity are under construction today. This is a significant rate of growth in new reactor construction.

MANAGEMENT’S DISCUSSION AND ANALYSIS 15

India, Russia and South Korea are expanding their nuclear generating capacity, and China continues to lead the growth, with 29 reactors under construction. Near the end of 2012, China resumed approvals of new reactor construction.

In the UK, government commitment to nuclear energy is strong, driven by concerns about energy security and the need to limit CO₂ emissions. In 2012, the first site licence in 25 years was granted at the Hinkley Point nuclear power plant, where two new units are planned. The US also continues to make progress toward new nuclear development with one unit under construction and preparatory work ongoing at four units.

Other previously non-nuclear countries are either moving ahead with their reactor construction programs or considering adding nuclear to their energy programs in the future. The United Arab Emirates (UAE) recently became the first non-nuclear country in 27 years to start building its first nuclear power plant. The UAE is proceeding with its plans to have 5.6 gigawatts of nuclear capacity in place by 2020, and in 2012 secured long-term fuel supply contracts for those reactors. In Saudi Arabia, where power demand has been increasing by 7% to 8% annually, plans to build 16 reactors by 2030 have been announced. Vietnam, Bangladesh, Poland, Turkey, and Belarus are also moving forward with plans to proceed with nuclear power development.

DEMAND FOR URANIUM IS GROWING

Not surprisingly, as the number of reactors grows, so too does the demand for uranium.

We expect world demand of approximately 2.2 billion pounds over the next 10 years, which includes both world consumption and strategic inventory building. By 2022, we expect world uranium demand to be about 240 million pounds per year, representing average annual growth of about 3%.

SUPPLY IS TIGHTENING

While demand is expected to increase over the next decade, 2012 saw a great deal of supply destruction as many producers announced delays and cancellations to their projects. We were counted among this group with the adjustment to our uranium growth strategy in response to market conditions. The resulting impact on the long-term outlook for uranium supply could be significant if these delays continue.

We estimate roughly two-thirds of global uranium supply over the next 10 years to come from existing primary production—mines that are currently in commercial operation—and about 15% to come from existing secondary supply sources. However, most secondary sources are finite and will not meet long-term needs. Currently, one of the largest sources of secondary supply is uranium derived from the Russian HEU commercial agreement, which is scheduled to end in 2013 and leave a gap of about 24 million pounds per year. This volume is more than our current total annual production.

16 CAMECO CORPORATION

The result is that we estimate about 20% of supply will need to come from new sources at a time when new projects are being delayed or cancelled because of current market conditions. The situation is exacerbated by barriers to entry and lead times for new uranium production being as long as 10 years or more, depending on the deposit type and location. As conditions continue to evolve, it is important to keep an eye on supply.

WE ARE WELL POSITIONED

Despite the current challenging industry environment, we are well positioned to continue to succeed and meet the growing demand for uranium. We have advantages like extensive mineral reserves and resources, low cost operations, a strong contract portfolio, experienced employees and a growth strategy that will allow us to remain competitive in challenging environments and respond quickly when the market signals more production is needed.

MANAGEMENT’S DISCUSSION AND ANALYSIS 17

Our strategy

Our strategy is to increase annual uranium supply to 36 million pounds by 2018, subject to market conditions, and to invest in opportunities across the nuclear fuel cycle that we expect will complement and enhance our business.

Uranium: growing production

The focus of our growth strategy is our uranium segment. Over the next 10 years, we expect annual consumption to increase by 50 million pounds as new reactors come on line. Deliveries under the Russian HEU commercial agreement will end in 2013, and the industry will need new uranium production. Lead-times in our industry are long, so we are preparing our assets today to make sure we can be among the first to respond when the market signals new production is needed. However, our production decisions will always be made with a focus on profitability.

Given the current challenging market environment, we are pursuing our growth with an increased focus on execution. The projects we are pursuing to contribute to our target of 36 million pounds of annual supply by 2018 are those that provide the most certainty in the near-term, and are primarily brownfield development. Our growth will come from operating properties, expansions at operating properties and our development projects.

We plan to achieve our growth with a focus on enhancing our nearer term financial picture by spreading our capital spending over a longer period and decreasing project related expenses. Of course, all of our project decisions will depend upon market conditions and profitability. We continue to monitor the market closely, and will adjust our plans in response to market signals.

We advance each project through a stage gate process that includes several defined decision points in the assessment and development stages. At each point, we re-evaluate the project based on current economic, competitive, social, legal, political and environmental considerations. If it continues to meet our criteria, we proceed to the next stage. This process allows us to build a pipeline of projects ready for a production decision and minimize expenditures on projects whose feasibility has not yet been determined.

18 CAMECO CORPORATION

OPERATING PROPERTIES

Our current sources of production are McArthur River/Key Lake, Rabbit Lake, Smith Ranch-Highland, Crow Butte and Inkai. We expect about 60% of our total 2018 annual supply will come from mines that are already operating.

BROWNFIELD EXPANSIONS AND DEVELOPMENT PROJECTS

We expect the rest of the 36 million pounds to come primarily from brownfield expansions and development projects, which provide the benefit of existing infrastructure, workforce and positive relationships with communities, governments and regulators. These include:

• bringing Cigar Lake into production

• expanding production at McArthur River and our US operations

• refurbishing and expanding the Key Lake mill

• working to extend the life of the Rabbit Lake mine

• advancing the process for extracting uranium from the Talvivaara mine in Finland

We previously estimated capital costs on development projects and projects under evaluation to be between $200 and $400 million per year for the next three years. However, we adjusted our strategy down from 40 million pounds to 36 million pounds of annual supply by 2018, and we now estimate capital costs for our brownfield expansions and development projects to be about $310 million in 2013, and between $140 and $190 million per year in growth capital for 2014 and 2015. See Capital Spending on page 42.

MAINTAINING OPTIONALITY

We will also continue to advance our other projects at a pace measured to market opportunities in order to respond should the market reflect the need for more uranium. These projects are:

• increasing production at Inkai

• the Millennium project

• the Kintyre project

• the Yeelirrie project

We previously expected to spend between $20 and $25 million per year on average for the next three years to assess the feasibility of projects under evaluation. We expect to spend about $24 million in 2013 to preserve optionality for these projects. Based on market conditions, we currently expect to spend less than $5 million per year in 2014 and 2015.

MANAGEMENT’S DISCUSSION AND ANALYSIS 19

Exploration: sustaining long-term production

Our exploration program is directed at replacing mineral reserves as they are depleted by our production, and ensuring our growth beyond 2018. We have maintained an active program even during periods of weak uranium prices, which has helped us secure land with exploration and development prospects that are among the best in the world, mainly in Canada, Australia, Kazakhstan and the US. Globally, our land holdings total 3.7 million hectares (9.3 million acres). In northern Saskatchewan alone, we have direct interests in 584,000 hectares (1.4 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin. Many of our prospects are located close to our existing operations where we have established infrastructure and capacity to expand.

For properties that meet our investment criteria, we will partner with other companies through strategic alliances, equity holdings and traditional joint venture arrangements. Our leadership position and industry expertise in both exploration and corporate social responsibility make us a partner of choice.

20 CAMECO CORPORATION

Fuel services: capturing synergies

UF₆ AND UO₂

We control about 25% of world UF₆ conversion capacity and are the only commercial supplier of natural UO₂. Our focus is on cost-competitiveness and operational efficiency.

Our fuel services segment is strategically important because it helps support the growth of the uranium segment. Offering a range of products and services to customers helps us broaden our business relationships and expand our uranium market share.

ENRICHMENT

We also continue to explore innovative areas like laser enrichment technology to broaden our fuel cycle participation and help us serve our customers more effectively.

Today, uranium enrichment is the second largest value component, after uranium, in a typical light water reactor fuel bundle. The enrichment market has the same customer base as the uranium market, and most of the world’s commercial nuclear reactors need enriched uranium.

Uranium and enrichment can be substituted for each other to some extent to produce a given amount of enriched uranium product. For example, when uranium is relatively more expensive than enrichment, it is more cost-effective to reduce the amount of uranium feedstock and use more enrichment capacity. When enrichment is relatively more expensive, it makes sense to use more uranium and less enrichment to produce the same amount of enriched uranium product.

Enrichment has the potential to be a significant growth area for us, and offers operational synergies that could significantly enhance profit margins for both our uranium business and future enrichment operations.

NUKEM: strengthening our position

Our January 2013 acquisition of NUKEM complements our uranium segment by strengthening our position in nuclear fuel markets and improving our access to unconventional and secondary sources of supply. We expect it to deliver solid cash flow and sustainable profitability.

Electricity: capturing added value

Our investment in BPLP has been an excellent source of cash flow. Our focus is on maintaining steady cash flow and building synergies with our other segments. Ontario’s Long Term Energy Plan has earmarked 6,300 MW of long-term capacity needed from the Bruce Power site. This means that all of the units at Bruce B will need to be refurbished and we will have an opportunity to invest if BPLP decides to proceed. We would base this investment decision on the underlying value proposition and the strategic fit with our other growth objectives. The timing of this opportunity is still unclear, as Bruce Power is working with the Ontario Power Authority (OPA) on a possible refurbishment schedule recognizing the significant role the nuclear units play in maintaining system reliability and the importance of sequencing these activities over a multi-year period.

Acquisition program

We have a dedicated team looking for acquisition opportunities that could further add to our supply, support our sales activities and complement and enhance our business in the nuclear industry. We will invest when an opportunity is available at the right time and the right price. We strive to pursue corporate development initiatives that will leave us and our shareholders in a fundamentally stronger position.

MANAGEMENT’S DISCUSSION AND ANALYSIS 21

Capital Allocation

We remain on a cautious growth path, taking a balanced approach to capital allocation and subjecting all investment decisions to a rigorous and disciplined review process. This review involves an assessment of our overall liquidity, the overall level of investment needed, and the prioritization of our investment choices based on the merits of each opportunity. Our assessment also takes expected levels of future operating cash flow and the cost and availability of new financing into account. In the context of our uranium growth strategy, we are focused on opportunities to leverage existing infrastructure (brownfield expansion), and on projects with greater near-term certainty. The review may result in good opportunities being held back in favour of higher return projects, and should allow us to generate the best return on investment decisions when we are faced with multiple prospects. Future changes in the market could impact the timing and amount of cash available for future investment in capital projects, acquisitions, dividends, debt repayments and other uses of capital.

This discussion of our strategy and our process to increase our annual uranium supply by 2018 is all forward-looking information. It is based on the assumptions and subject to the material risks discussed on pages 3 and 4, and specifically on the assumptions and risks listed here.

ASSUMPTIONS

Our statements about increasing annual supply by 2018 to 36 million pounds reflect our current supply target for 2018. Although we are confident in our efforts to reach that target, we cannot guarantee that we will. We have made assumptions about 2018 production levels at each of our existing operating mines. We have also made assumptions about the development of mines that are not operating yet and their 2018 production levels, and about uranium by-product supply from the Talvivaara mine. We believe these assumptions are reasonable, individually and together, but if an assumption about one or more mines proves to be incorrect, we will not reach our 2018 target supply level unless the shortfall can be made up in other ways.

Material risks that could prevent us from reaching our target

• we cannot locate additional mineral reserves to extend Rabbit Lake’s mine life to maintain production

• our partner or the Kazakh government does not support an increase in production to the expected level at Inkai, blocks 1 and 2, or we do not reach the full production level as quickly as we expect

• development at Cigar Lake is not completed on schedule, or we do not reach the full production level as quickly as we expect

• the Key Lake mill does not have enough capacity to handle anticipated production increases, and we are not able to expand its capacity or to identify alternative milling arrangements

• we are unable to obtain the expected level of uranium by-product supply from the Talvivaara mine

• our mine expansion and development projects do not proceed or, if they do, are not completed on schedule or do not reach full production levels as quickly as we expect

• uranium prices and development and operating costs make it uneconomical to proceed with our mine expansion and development projects

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

• disruption in production or development due to natural phenomena, labour disputes (including an inability to renew agreements with unionized employees at McArthur River and Key Lake), political risks, blockades or other acts of social or political activism, lack of tailings capacity, or other development and operation risks.

22 CAMECO CORPORATION

Building on our strengths

WORLD-CLASS ASSETS

We have extensive mineral reserves and resources, a large portfolio of low-cost mining operations, and geographically diverse uranium assets with controlling interests in the world’s largest high-grade uranium reserves.

EMPLOYEE EXPERTISE

Our company is filled with talented and creative people who are committed to achieving our strategy in a manner consistent with our corporate values of protecting people and the environment, excellence and integrity.

STRONG CUSTOMER RELATIONSHIPS

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.

URANIUM PRICE LEVERAGE

Our plans to increase our supply of uranium, combined with our contracting strategy, are designed to give us leverage when uranium prices go up, and to protect us when prices decline.

FINANCIAL STRENGTH

We are in a strong financial position to proceed with our growth plans. We are working to ensure our capital structure is appropriate and adds value for our shareholders.

DISCIPLINED PORTFOLIO MANAGEMENT

We have a disciplined portfolio management process that incorporates all capital projects into a single capital plan and uses a stage gate decision process (see page 18). This ensures our capital projects are aligned with our strategic objectives, and that business benefits are measurable and attainable.

FOCUSED RISK MANAGEMENT

We have a formal enterprise-wide risk management process that we apply consistently and systematically across our organization. Risk management is a core element of our strategy and our objectives, and we use it to continuously improve our organization. It will underpin decisions we make as we move ahead with our growth strategy.

INNOVATION

We are always looking for ways to improve processes, to increase safety and environmental performance, and reduce costs. We are currently working on innovative projects in all aspects of operations, including upgrading the Key Lake and Rabbit Lake mills.

REPUTATION

We believe strongly in our values and apply them consistently in our operations and business dealings. We are recognized as a reliable supplier and business partner, strong community supporter and employer of choice.

MANAGEMENT’S DISCUSSION AND ANALYSIS 23

Managing our growth

Our ability to grow is a function of our people, processes, assets and reputation, and the ability to enhance and leverage these strengths to add value and build competitive advantage.

We use four categories to define what we are committed to deliver, and how we will measure our results:

• outstanding financial performance

• a safe, healthy and rewarding workplace

• a clean environment

• supportive communities

We introduced these measures of success to proactively address the financial, social and environmental aspects of our business. We believe that each is integral to our overall success and that, together, they will ensure our long-term sustainability.

FOCUS ON LONG-TERM SUSTAINABILITY

Companies are under growing scrutiny for the way they conduct their business, and there has been a significant increase in stakeholder expectations for environmentally and socially responsible business practices.

Rather than viewing sustainable development as an ‘add-on’ to traditional business activity, we see it as integral to the way we do business, and have made it a strategic priority, integrating it into our objectives and compensation policies.

You can find out more in our 2012 sustainable development report, which is on our website (cameco.com).

OUTSTANDING FINANCIAL PERFORMANCE

Our financial results depend heavily on our sales and production volumes, on the cost of supply, and on the prices we realize in our uranium and fuel services segments.

Managing our supply and costs

Uranium and Fuel Services

We sell more uranium than we produce every year. To meet our delivery commitments, we use uranium obtained:

• from our own production

• through long-term purchase agreements and on the spot market

• from our existing inventory (we target inventories of about six months of forward sales of uranium concentrates and UF₆)

Like all mining companies, our uranium segment is affected by the rising cost of inputs like labour and fuel. In 2012, labour, production supplies and contracted services made up 91% of the production costs at our uranium mines. Labour (37%) was the largest component. Production supplies (28%) included fuels, reagents and other items. Contracted services (26%) included mining and maintenance contractors, air charters, security and ground freight.

Starting in early 2014, we expect to begin to recognize the profits or losses related to Cigar Lake’s operating activities. All expenditures incurred before that time are expected to be capitalized as development costs. Depending on the actual timing of the rampup to the full production rate, we expect that the cost of material produced from Cigar Lake will initially be higher than our other sources of production, which is likely to temporarily increase our unit cost of sales.

Operating costs in our fuel services segment are mainly fixed. In 2012, labour accounted for about 54% of the total. The largest variable operating cost is for energy (natural gas and electricity), followed by zirconium and anhydrous hydrogen fluoride.

To help us operate efficiently and cost-effectively as we grow, we manage operating costs and improve plant reliability by prudently investing in production infrastructure, new technology and business process improvements. In addition, in the third quarter of 2012, we adjusted our growth strategy to allow us to spread our capital expenditures over a longer period of time and decrease our administration and project related costs.

24 CAMECO CORPORATION

See Our strategy on page 18 for more information.

Our costs are also affected by the purchases of uranium and conversion services we make under long-term contracts and on the spot market.

Prices under our long-term purchase contracts are lower than the current published spot and long-term prices. Our most significant long-term purchase contract is the Russian HEU commercial agreement, which ends this year. Our final purchase is expected to be about 10 million pounds under this agreement. The purchase price escalates with inflation and was agreed to in 2001 when uranium prices were much lower than today. In 2008, pricing on a portion of the volumes available to us in 2011 through to 2013, was renegotiated. This will affect about 3 million of the 10 million pounds we expect to purchase under the agreement in 2013 and using a $50 (US) per pound uranium spot price, the average price for those pounds is expected to increase by about $11 (US) per pound (including an adjustment for inflation).

After the Russian HEU commercial agreement ends this year, we expect to maintain our sales volumes using a combination of sources including:

• increased production from various supply sources (including the rampup of Cigar Lake)

• normal-course purchases of uranium under existing and/or new arrangements

• discretionary use of inventories

We expect our purchases will result in profitable sales; however, the cost of purchased material is likely to be higher than our other sources of supply.

In addition, we will make spot purchases to take advantage of opportunities to place material into higher priced contracts. We make spot purchases prudently, looking at the spot price and other factors relating to our business to decide whether a spot purchase is appropriate. This activity gives us insight into the underlying market fundamentals and is a source of profit.

Managing contracts

Uranium and Fuel Services

We sell uranium and fuel services directly to nuclear utilities around the world, as uranium concentrates, UO₂, UF₆, conversion services or fuel fabrication.

Uranium is not traded in meaningful quantities on a commodity exchange. Utilities buy the majority of their uranium and fuel services products under long-term contracts with suppliers, and meet the rest of their needs on the spot market.

Our extensive portfolio of long-term sales contracts—and the long-term, trusting relationships we have with our customers—are core strengths for us. We currently have commitments to supply approximately 270 million pounds of U₃O₈ under long-term contracts with 52 customers worldwide. Our five largest customers account for 47% of these commitments, and 38% of our committed sales volume is attributed to purchasers in the Americas (US, Canada and Latin America), 39% in Asia and 23% in Europe.

Because we deliver large volumes of uranium every year, our net earnings and operating cash flows are affected by changes in the uranium price. Our contracting strategy is to secure a solid base of earnings and cash flow by maintaining a balanced contract portfolio that maximizes our realized price. Market prices are influenced by the fundamentals of supply and demand, geopolitical events, disruptions in planned supply and other market factors. Contract terms usually reflect market conditions at the time the contract is accepted, with deliveries beginning several years in the future.

MANAGEMENT’S DISCUSSION AND ANALYSIS 25

Our current uranium contracting strategy is to sign contracts with terms between 5 and 10 years (on average) that include mechanisms to protect us when market prices decline, and allow us to benefit when market prices go up. Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio.

• Fixed-price contracts are typically based on the industry long-term price indicator at the time the contract is accepted, adjusted for inflation to the time of delivery.

• Market-related contracts may be based on either the spot price or the long-term price as quoted at the time of delivery, and often include floor and ceiling prices adjusted for inflation.

This is a balanced approach that reduces the volatility of our future earnings and cash flow, and that we believe delivers the best value to shareholders over the long term. It is also consistent with the contracting strategy of our customers. This strategy has allowed us to add increasingly favourable contracts to our portfolio that will enable us to benefit from any increases in market prices in the future.

The majority of our existing contracts include a supply interruption clause that gives us the right to reduce, on a pro rata basis, defer or cancel deliveries if there is a shortfall in planned production or in deliveries under the Russian HEU commercial agreement.

We are heavily committed under long-term uranium contracts through 2016, so we are being selective when considering new commitments.

Since March 2011, the nuclear industry has been addressing challenges related to the events in Japan. We have been working with our customers who were directly impacted by those events to help them manage their contractual obligations and excess inventories. As clarity is slowly gained around the situation in Japan, we are receiving fewer requests for assistance. In the limited instances where customers have requested help to manage their inventories, we have agreed to consider arrangements that are financially beneficial to us. We realized benefits from these contract improvement opportunities in 2011 and 2012. We expect that these requests will continue to decline as Japan gets closer to restarting its nuclear fleet.

The majority of our fuel services contracts are at a fixed price per kgU, adjusted for inflation, and reflect the market at the time the contract is accepted.

We have a similar marketing strategy for UF6 conversion services. We sell our conversion services to utilities in the Americas, Europe and Asia and primarily through long-term contracts. We currently have UF6 conversion services commitments of approximately 80 million kilograms of uranium under long-term contracts with 43 customers worldwide. Our five largest customers account for 41% of these commitments, and of our committed UF6 conversion services volume, 51% is attributed to purchasers in the Americas, 33% in Asia and 16% in Europe.

NUKEM Gmbh

NUKEM Gmbh (NUKEM), which we acquired in January 2013, has access to contracted volumes and inventories in diverse geographic locations as well as scope for opportunistic trading of uranium and uranium-related products. This enables NUKEM to provide a wide range of solutions to its customers that may fall outside the scope of typical uranium sourcing and selling arrangements. Its trading strategy is non-speculative and seeks to match quantities and pricing structures of its long-term supply and delivery contracts, minimizing exposure to commodity price fluctuations and locking in profit margins.

NUKEM’s main customers are commercial nuclear power plants using enriched uranium fuel, typically large utilities that are either government-owned, or large-scale utilities with multi-billion market capitalizations and strong credit ratings. NUKEM also trades with converters, enrichers, other traders and investors. It has uranium and uranium-related products under contract until 2022. NUKEM is party to the Russian HEU commercial agreement and will receive its final delivery of approximately 2 million pounds in 2013.

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A SAFE, HEALTHY AND REWARDING WORKPLACE

We strive to foster a safe, healthy and rewarding workplace at all of our facilities, and measure progress against key indicators, such as conventional and radiation safety statistics, employee sentiment toward the company and employment creation.

To achieve our growth objectives, we continue to build an engaged, qualified and diverse organization capable of leading and implementing our strategies. Our challenge is to retain our current workforce and compete for the limited number of qualified people available, both to replace retiring employees and to support our growth. Our long-term people strategy includes identifying critical workforce segments and planning our workforce to meet this challenge.

Our approach is working. We were recognized in a number of ways for our employee programs in 2012: the Financial Post named us as one of the Top 10 Best Companies to Work for in Canada for the third year in a row; Mediacorp named us one of Canada’s Top 100 Employers and also one of Canada’s Best Diversity Employers, both for the third year in a row; and we were named one of Canada’s Top Employers for Young People by Mediacorp. You can find out more about our awards on cameco.com.

A CLEAN ENVIRONMENT

We are committed to operating our business with respect and care for the local and global environment. We strive to be a leader in environmental practices by complying with and moving beyond legal and other requirements, and by integrating environmental leadership into everything we do.

We continually refine our objectives for environmental leadership and revisit the indicators we use to measure our progress in protecting the air, water and land near our operations, and in reducing the amount of waste we generate.

Reducing our impact

We work to reduce our impact on the environment by monitoring and implementing measures to reduce our effect on air, water and land, optimizing the amount of energy we consume, and managing waste.

• Water: We have employed water treatment technologies that have improved the quality of the water released from our Saskatchewan uranium mining and milling operations.

• Waste: We continue to work on projects to reduce waste, improve the reclamation process and manage waste rock more effectively at all of our operations. In 2012, Blind River successfully removed a large inventory of waste materials stored at the facility. To ensure effective on-going waste management, the fuel services division has initiated plans to process these materials on an on-going basis to ensure accumulation does not occur in the future.

• Air: We are maximizing the lifespan of our operating sites to limit the areas impacted by our operations, including revitalizing the Key Lake mill (in operation for 30 years) and Rabbit Lake mill (in operation for 38 years). In doing so, we have improved air emissions by replacing some existing facilities.

Like other large industrial organizations, we use chemicals in our operations that could be hazardous to our health and the environment if they are not handled correctly. We train our employees in the proper use of hazardous substances and in emergency response techniques.

AWARDED FOR SOCIAL RESPONSIBILITY

We are the 2013 recipient of the Prospectors and Developers Association of Canada’s Environmental and Social Responsibility award.

The award recognizes our outstanding accomplishments in establishing good community relations to support our exploration and mining operations.

MANAGEMENT’S DISCUSSION AND ANALYSIS 27

We are always investing in management systems and safety initiatives to achieve operational excellence and reliability, which also continues to improve our safety and environmental performance. We have incorporated life cycle value assessment into our project management and engineering processes to ensure social, environmental and financial risks have been more fully considered when designing new facilities.

SUPPORTIVE COMMUNITIES

To maintain public support for our operations (our social licence to operate) and our global reputation, we need the respect and support of communities, indigenous people, governments and regulators affected by our operations.

We work with communities who are affected by our activities to tell them what we are doing and to receive feedback and further input to build and sustain their trust. For example, in Saskatchewan, we participate in the Athabasca Working Group and Northern Saskatchewan Environmental Quality Committee. In Ontario, we liaise with our communities by regularly holding educational and environment-focused activities. Public opinion research shows that we have strong local support in these communities.

We build and sustain the trust of local communities by being a leader in corporate social responsibility (CSR). Through our CSR initiatives, we educate, engage, employ and invest in the people in the regions where we operate.

For example, in northern Saskatchewan in 2012:

• just under 50% of the employees at our northern mines were local residents (756) and were paid over $73 million in wages

• over $460 million was paid to northern businesses, which provided 73% of services to our northern minesites. This is the most that we have ever procured from northern vendors in one year.

• we made over 85 community visits in northern Saskatchewan to discuss potential projects at our northern operations and to provide career information to high school students and community members

• we donated over $1.7 million to northern and aboriginal initiatives for youth, health and wellness, education and literacy, and culture and recreation

• we provided $100,000 in scholarships to post-secondary students

In an effort to formalize our relationship with local communities and guide future cooperation and the sharing of benefits from our operations, we negotiated the first of several collaboration agreements with northern Saskatchewan communities in 2012. In a joint effort with AREVA Resource Canada Inc., we signed a collaboration agreement with the Northern Village of Pinehouse and the Kineepik Metis Local Inc. The agreement sets out specific commitments by the mining companies with respect to workforce development, business development, community engagement, environmental stewardship and community investment. The agreement confirms the support of the village and local for our existing projects and operations subject to our continued work to protect the health and safety of people and the environment.

Our operations are closely regulated to give the public comfort that we are operating in a safe and environmentally responsible way. Regulators approve the construction, startup, continued operation and any significant changes to our operations. Our operations are also subject to laws and regulations related to safety and the environment, including the management of hazardous wastes and materials.

Our objectives are consistent with those of our regulators—to keep people safe and to protect the environment. We pursue these goals through transparent and respectful efforts with all of our regulators. We work to earn their trust and that of stakeholders by continually striving to protect people and the environment.

28 CAMECO CORPORATION

Measuring our results

2012 OBJECTIVES	RESULTS
Outstanding financial performance
Production •   Achieve budgeted production from our uranium and fuel services segments.	Achieved •   Our share of U3O8 production was 21.9 million pounds, or 99% of plan, and we produced 14.2 million kgU at fuel services, or 99% of plan.
McArthur River •   Implement productivity improvements to maintain planned production during mining zone transitions.	Achieved •   Made productivity improvements on cycle times, and changed the sequencing of the raises in zone 2, panel 5. Mitigated the risk to production in 2013 associated with the transition to the upper mining area of zone 4.
Financial measures Corporate performance •   Achieve budgeted net earnings and cash flow from operations (before working capital changes).	Exceeded •   Adjusted net earnings1 were $447 million, 20% higher than budget. Cash flow from operations (before working capital changes)1 was $717 million, 22% higher than budget.
Costs •   Achieve budgeted unit operating costs and corporate support costs.	Achieved •   Actual consolidated unit operating costs were in line with budget. Unit operating costs for uranium were $20.46 or 3% higher than budget and unit operating costs for fuel services were 2% lower than our budget of $17.11 per kgU. For the purposes of calculating performance on this objective, unit costs are weighted 70% for uranium and 30% for fuel services. Direct administrative expenses (corporate support costs) at year-end were 3% better than budgeted costs of $168 million. Our minimum target was to achieve budgeted unit costs on a consolidated basis.
Growth •   Meet regulatory project milestones and stage gate assessments on projects that support our Double U growth strategy.	Achieved •   Licence renewal applications were submitted for McArthur River, Key Lake and Rabbit Lake sites. Draft Environmental Impact Statements were submitted for the Millennium project, Key Lake extension project, and Eagle Point water management. Licence renewals were received for Blind River refinery, Port Hope conversion facility and Cameco Fuel Manufacturing. Engineering, procurement and construction management (EPCM) approach rolled out for McArthur River expansion, Millennium and the Port Hope Vision in Motion projects, and EPCM negotiations completed and firms retained. In Q4, we adjusted our growth strategy down from 40 million to 36 million pounds U3O8 by 2018.
Cigar Lake •   Advance the project towards startup in 2013 by successfully completing critical activities planned for 2012.	Achieved •   Completed the sinking of shaft 2 to its final depth of 500 metres and began installing shaft infrastructure. Assembled the first jet boring system unit underground, moved it to a production tunnel and began preliminary commissioning and system testing. Cigar Lake is a challenging deposit to mine. Completion of these critical milestones requires careful planning and deliberate execution.
Inkai •   Advance block 3 mineral resource delineation drilling and complete the test leach facility. •   Receive approval to increase annual production from blocks 1 and 2 to design capacity of 5.2 million pounds per annum (100% basis). Continue to advance our longer-term objective of receiving approval to double annual production from blocks 1 and 2, extend the lease terms and secure block 3 mining rights.	Partially achieved •   Received regulatory approval for the detailed block 3 delineation and test leach work programs. Continued to advance block 3 mineral resource delineation, started technological drilling of test wellfields, continued infrastructure development and started construction of a test leach facility. Partially achieved •   We continue to await government approval of an amendment to the resource use contract to increase annual production from blocks 1 and 2 to 5.2 million pounds per year (100% basis). •   We signed a binding memorandum of agreement with our partner setting out the framework to increase annual production to 10.4 million pounds (100% basis), to extend the term of Inkai’s resource use contract, and to co-operate on the development of uranium conversion capacity, with the primary focus on uranium refining. Implementation of the MOA in this complex and developing regulatory environment is subject to further agreements and receipt of all necessary Canadian and Kazakhstan government approvals,

¹  We use adjusted net earnings and cash flow from operations (before working capital changes) as a more meaningful way to compare our financial performance from period to period. These are not standard measures and not a substitute for financial information prepared in accordance with IFRS. Other companies may calculate these measures differently. Cash flow from operations (before working capital changes) is derived by adding amounts included in “Other operating items” to the line item “Net cash provided by operations” presented in the consolidated statements of cash flows in our 2012 audited financial statements. See Non-IFRS measures-Adjusted net earnings on page 34 and note 26 to our audited financial statements for more information.

MANAGEMENT’S DISCUSSION AND ANALYSIS 29

2012 OBJECTIVES	RESULTS
Outstanding financial performance (continued)
Growth (continued) Kintyre •   Continue to advance project evaluation in 2012 and decide if we will proceed to feasibility.	Achieved •   We drill tested ten additional prospective areas on the property in 2012 and no additional resources were identified. We completed the prefeasibility study and decided not to proceed with the feasibility study at this time due to challenging project economics.
Exploration and innovation •   Replace mineral reserves and resources at the rate of annual U3O8 production based on a three-year rolling average.	Achieved •   Over the last three years, mineral reserves decreased by 13.5 million pounds compared to production of 67.2 million pounds, measured and indicated resources increased by 104.4 million pounds and inferred resources decreased by 67 million pounds. On average, production was replaced and exceeded by nearly 8 million pounds per year in each of the last three years (2010 to 2012). Replacing our reserves and resources is fundamental to our long-term success.
Capital project management •   Deliver capital projects planned for completion in 2012 within budget and on schedule.	Partially achieved •   The 165 capital projects that closed in 2012 were on schedule but 11.9% over our budget of $300 million.

2012 OBJECTIVES	RESULTS
Safe, healthy and rewarding workplace
•   Strive for no lost-time injuries at all Cameco-operated sites and, at a minimum, maintain a long-term downward trend in combined employee and contractor injury frequency and severity, and radiation doses.	Achieved •   Safety performance was strong in 2012 with a downward trend in lost-time frequency and severity with the best lost-time frequency performance in the company’s history at 0.13 versus a target of 0.29. Average radiation doses were low and stable.
•   Attract, retain, engage and develop employees in support of current and future operations and establish succession pools for key positions.	Partially achieved •   Turnover rate of 7.5% was lower than the targeted performance range of 8.1% to 9.9%; but there was a higher than expected turnover rate for new hires within the first year of employment at 12.4%. Cameco was listed as both a Top 100 Employer and on the Financial Post’s 10 Best Companies to Work For, in addition to receiving awards for being among Saskatchewan’s top Employers, Canada’s Best Diversity Employers, and a Top Employer of Canadians over 40.

2012 OBJECTIVES	RESULTS
Clean environment
•   Strive for zero reportable environmental incidents, reduce the frequency of incidents and have no significant incidents at Cameco-operated sites.	Achieved •   We incurred a total of 28 reportable environmental incidents in 2012, less than our long-term average of 40 reportable environmental incidents per year. There were no significant environmental incidents.

2012 OBJECTIVES	RESULTS
Supportive communities
•   Develop long-term relationships by engaging with regulators and other stakeholders important to our sustainability. Secure continued support from our employees, impacted communities, investors, governments and the general public through communications, community investment and business development.	Achieved •   Maintained positive relationships with groups affected by our operating activities. Received a higher management credibility rating of 79% in our investor perception study compared to 74% in 2011. Maintained strong corporate trust ratings in Saskatchewan (7.52/10 compared to 7.24 in 2011) and Port Hope (8.03/10 compared to 7.98 in 2011); polling was not conducted in the US this year.
•   Implement Cameco’s corporate social responsibility policy to advance Cameco projects in all locations and secure support from indigenous communities affected by our operations.	Achieved •   A revised corporate social responsibility policy was developed and approved, and roll-out to operations commenced as planned. Meetings in local communities in northern Saskatchewan, Nunavut, James Bay and Australia, took place throughout the year. Successfully concluded the negotiation and signing of the Martu/Cameco Mining Development Agreement in Australia. Signed a collaboration agreement with the Northern Village of Pinehouse and Kineepik Metis Local Inc. in northern Saskatchewan. Negotiations are in progress with other communities in northern Saskatchewan.

30 CAMECO CORPORATION

2013 objectives

We set corporate, business unit and departmental objectives every year under our four measures of success, and these become the foundation for a portion of annual employee compensation.

2013 OBJECTIVES

Outstanding financial performance

• Achieve targeted adjusted net earnings and cash flow from operations.

• Execute capital projects within scope, on time and on budget.

• Achieve production at Cigar Lake in 2013, and advance other activities needed to achieve medium and long-term growth objectives.

Safe, healthy and rewarding workplace

• Improve workplace safety performance at all sites.

• Attract and retain the employees needed to support operations and growth.

Clean environment

• Improve environmental performance at all sites.

Supportive communities

• Build and sustain strong stakeholder support for our activities.

MANAGEMENT’S DISCUSSION AND ANALYSIS 31

Financial results

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

33	2012 consolidated financial results
40	Outlook for 2013
41	Liquidity and capital resources
47	2012 financial results by segment
47	Uranium
51	Fuel services
52	NUKEM
53	Electricity
55	Fourth quarter results
55	Fourth quarter consolidated results
56	Quarterly trends
57	Fourth quarter results by segment

32 CAMECO CORPORATION

2012 consolidated financial results

Starting in the first quarter of 2013, IFRS 11 – Joint Arrangements requires that we account for our interest in Bruce Power Limited Partnership (BPLP) using equity accounting. We will recast our quarterly results for 2012 for comparative purposes.

For the purposes of this report our interest in BPLP is presented in accordance with the proportionate consolidation method.

HIGHLIGHTS DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED)	2012		2011		2010		CHANGE FROM 2011 TO 2012
Revenue		2,321		2,384		2,124		(3	)%
Gross profit		723		776		772		(7	)%
Net earnings attributable to equity holders		266		450		516		(41	)%
$ per common share (basic)		0.67		1.14		1.31		(41	)%
$ per common share (diluted)		0.67		1.14		1.31		(41	)%
Adjusted net earnings (non-IFRS, see below)		447		509		497		(12	)%
$ per common share (adjusted and diluted)		1.13		1.29		1.26		(12	)%
Cash provided by operations (after working capital changes)		644		745		530		(14	)%

Net earnings

Our net earnings attributable to equity holders (net earnings) were $266 million ($0.67 per share diluted) compared to $450 million ($1.14 per share diluted) in 2011 mainly due to:

• a $168 million write-down of our investment in the Kintyre project

• lower earnings from our uranium business as a result of lower realized prices and an increase in the cost of product sold

• lower earnings from our fuel services business as a result of a decrease in sales volumes

• higher earnings from our electricity business due to higher generation and lower costs

• lower taxes due mainly to lower pre-tax earnings and a decrease in the expense recorded in 2012 related to our transfer pricing dispute with the Canadian Revenue Agency (CRA). See Income Taxes on page 37 for details.

Our net earnings normally trend with revenue, but in recent years have been significantly influenced by unusual items.

In 2011, our net earnings were $66 million lower than in 2010 primarily due to recording losses on foreign exchange derivatives compared to gains in 2010. We recorded an after tax loss of $3 million on foreign exchange derivatives in 2011 compared to an after tax profit of $55 million in 2010.

Impairment charge on non-producing property

During the fourth quarter of 2012, we recorded a $168 million write-down of the carrying value of our interest in Kintyre, our advanced uranium exploration project in Australia. Due to the weakening of the uranium market since the asset was purchased in 2008, no increase in mineral resources in 2012 and the decision not to proceed with the feasibility study, we concluded it was appropriate to recognize an impairment charge for this asset. Kintyre remains an important asset in our portfolio. However, given the current state of the market, it was necessary to reduce its carrying value at this time. The amount of the write-down was determined as the excess of the carrying value over the fair value less cost to sell based on the implied fair value of the resources in place using comparable market transaction metrics.

MANAGEMENT’S DISCUSSION AND ANALYSIS 33

Non-IFRS measures

ADJUSTED NET EARNINGS

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 adjusted for impairment charges on non-producing properties.

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.

To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the years ended 2012, 2011 and 2010, as reported in our financial statements.

($ MILLIONS)	2012			2011			2010
Net earnings attributable to equity holders		266			450			516
Adjustments
Adjustments on derivatives1 (pre-tax)		17			80			(26	)
Income taxes on adjustments to derivatives		(4	)		(21	)		7
Impairment charge on non-producing property		168			—			—
Adjusted net earnings		447			509			497

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.

The table below shows what contributed to the change in adjusted net earnings for 2012.

($ MILLIONS)
Adjusted net earnings – 2011		509
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 volume	(7	)
	Lower realized prices ($US)	(50	)
	Foreign exchange impact on realized prices	(1	)
	Higher costs	(70	)
	Hedging benefits	(14	)
	change – uranium	(142	)
Fuel services	Lower sales volume	(7	)
	Higher realized prices ($Cdn)	9
	Higher costs	(14	)
	Hedging benefits	(2	)
	change – fuel services	(14	)
Electricity	Higher sales volume	9
	Higher realized prices ($Cdn)	9
	Lower costs	66
	change – electricity	84
Other changes
Contract termination charge		(30	)
Higher administration expenditures		(24	)
Higher exploration expenditures		(12	)
Lower income taxes		75
Other		1
Adjusted net earnings – 2012		447

34 CAMECO CORPORATION

THREE-YEAR TREND

Our adjusted net earnings were relatively stable from 2010 to 2011 but declined in 2012.

The 2% increase from 2010 to 2011 resulted from:

• higher earnings from our uranium business due to higher realized prices, and an increase in sales volumes

partially offset by:

• an increase in the cost of product sold

• lower earnings from our electricity business mainly due to higher costs, lower realized prices and lower sales volumes

• lower earnings from our fuel services business resulting from higher costs, partially offset by higher sales volumes

• higher income taxes

The 12% decrease from 2011 to 2012 resulted from:

• lower earnings from our uranium business due to lower realized prices and an increase in our unit costs

• higher charges for administration and exploration

partially offset by:

• higher earnings from our electricity business mainly due to lower costs and higher sales volumes

• lower income taxes

Revenue

The table below shows what contributed to the change in revenue this year.

($ MILLIONS)
Revenue – 2011	2,384
Uranium
Lower sales volume	(19	)
Lower realized prices ($Cdn)	(51	)
Fuel services
Lower sales volume	(37	)
Higher realized prices ($Cdn)	8
Electricity
Higher output	33
Higher realized prices ($Cdn)	9
Other	(6	)
Revenue – 2012	2,321

See 2012 Financial results by segment on page 47 for more detailed discussion.

THREE-YEAR TREND

In 2011, revenue increased by 12% to a record $2.4 billion, due to higher sales volumes and record realized prices in our uranium business.

In 2012, revenue declined by 3% mainly due to a lower realized price for uranium, which was $1.57 per pound lower than the record price of $49.18 per pound in 2011.

MANAGEMENT’S DISCUSSION AND ANALYSIS 35

Average realized prices

			2012		2011		2010		CHANGE FROM 2011 TO 2012
Uranium1	$	US/lb		47.62		49.17		43.63		(3	)%
	$	Cdn/lb		47.61		49.18		45.81		(3	)%
Fuel services	$	Cdn/kgU		17.24		16.71		16.86		3	%
Electricity	$	Cdn/MWh		55		54		58		2	%

¹  Average realized foreign exchange rate ($US/$Cdn): 2012—$1.00, 2011 – $1.00 and 2010 – $1.05.

OUTLOOK FOR 2013

Effective January 1, 2013, with the adoption of IFRS 11 – Joint Arrangements, we will apply the equity method of accounting for our interest in BPLP and will no longer consolidate our share of their revenues. Our revenue outlook for 2013 does not include BPLP. For comparative purposes, our revenue for 2012 was $1,851,000 excluding BPLP. Furthermore, our outlook for 2013 presented below does not include any revenues expected to be recognized through NUKEM (see NUKEM on page 52).

We expect consolidated revenue to be up to 5% higher in 2013 due to:

• an increase in realized prices in the uranium business

• higher sales volumes in the fuel services business

• an increase in realized prices in the fuel services business

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly. In 2013, we expect that deliveries will be lower in the first quarter with only about 15% of the year’s deliveries scheduled for the first three months. We expect uranium sales for the balance of 2013 to be more heavily weighted (~60%) to the second half of the year. However, not all delivery notices have been received to date, which could alter the delivery pattern. Typically, we receive notices six months in advance of the requested delivery date.

Corporate expenses

ADMINISTRATION

($ MILLIONS)	2012		2011		CHANGE
Direct administration		163		147		11	%
Stock-based compensation		18		10		80	%
Total administration		181		157		15	%

Direct administration costs in 2012 were $16 million higher than in 2011. The increase in the year reflects the following:

• studies and analyses of various business opportunities

• enhancements to information systems

We recorded $18 million in stock-based compensation expenses this year under our stock option, deferred share unit, performance share unit and phantom stock option plans, an increase of $8 million compared to 2011. Our share price increased by 6.4% in 2012, whereas it declined markedly in 2011 following the Fukushima disaster. See note 27 to the financial statements.

Outlook for 2013

We expect administration costs (not including stock-based compensation) to be up to 5% lower than in 2012 due to expected reductions in business development and corporate administrative activities related to our adjusted growth plans.

36 CAMECO CORPORATION

EXPLORATION

In 2012, uranium exploration expenses were $97 million, an increase of $12 million compared to 2011 due largely to greater exploration activity in Saskatchewan. Our exploration efforts in 2012 focused on Canada, Australia, Kazakhstan and the United States.

Outlook for 2013

We expect exploration expenses to be about 5% to 10% lower than they were in 2012 due to:

• decreased evaluation activities at Kintyre

• a general reorganization of our global exploration portfolio that has allowed us to focus on our core projects in Saskatchewan, the US, Kazakhstan and Australia

FINANCE COSTS

Finance costs were $80 million compared to $74 million in 2011. The increase from last year largely reflects higher foreign exchange expenses and interest charges related to the debentures issued in the fourth quarter of 2012. See note 22 to the financial statements.

FINANCE INCOME

Finance income was $21 million compared to $25 million in 2011 due to lower levels of short-term investments in 2012.

GAINS AND LOSSES ON DERIVATIVES

In 2012, we recorded $39 million in gains on our derivatives compared to losses of $4 million in 2011. The gains reflect the strengthening of the Canadian dollar compared to the US dollar in 2012. See note 29 to the financial statements.

INCOME TAXES

We recorded an income tax recovery of $46 million in 2012 compared to an expense of $12 million in 2011. The change in the net expense was in part due to a decline in pre-tax earnings in 2012. The distribution of earnings between jurisdictions was also different compared to 2011. In 2012, we recorded losses of $320 million in Canada compared to $377 million in 2011, whereas earnings in foreign jurisdictions declined to $538 million from $839 million. The tax rate in Canada is higher than the average of the rates in the foreign jurisdictions in which we operate. The decline was also in part due to:

• a decrease in the expense recorded in 2012 related to the CRA transfer pricing dispute. In 2012, we increased our provision by $9 million whereas the amount recognized in 2011 was $27 million.

• additional certainty we received on particular tax provisions that allowed us to recognize a $9 million recovery in our income tax expense.

See note 24 to the financial statements.

On an adjusted earnings basis, we recognized a tax recovery of $42 million in 2012 compared to an expense of $33 million in 2011. The increase was related to the items noted above. Our effective tax rate was a recovery of 10% in 2012 compared to an expense of 6% in 2011. The table below presents our adjusted earnings and adjusted income tax expenses attributable to Canadian and foreign jurisdictions.

MANAGEMENT’S DISCUSSION AND ANALYSIS 37

($ MILLIONS)	2012			2011
Pre-tax Adjusted Earnings1
Canada2		(303	)		(298	)
Foreign2		706			839
Total pre-tax adjusted earnings		403			541
Adjusted Income Taxes1
Canada2		(70	)		(34	)
Foreign		28			67
Adjusted income tax expense (recovery)		(42	)		33
Effective tax rate		(10	)%		6	%

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 34).

Since 2008, CRA has disputed the offshore marketing company structure and related transfer pricing methodology we used for certain uranium sale and purchase agreements and issued notices of reassessment for our 2003 through 2007 tax returns. We believe it is likely that CRA will reassess our tax returns for 2008 through 2012 on a similar basis. Our view is that CRA is incorrect, and we are contesting its position. As a result we are pursuing our appeal rights under the Income Tax Act. However, to reflect the uncertainties of CRA’s appeals process and litigation, we have provided a total of $63 million for uncertain tax positions for the years 2003 through 2012. We believe 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. However, substantial success for the CRA would be material, and other unfavourable outcomes for the years 2003 to 2012 could be material, to our financial position, results of operations and cash flows in the year(s) of resolution. Due to the availability of elective deductions and tax loss carrybacks, we were not required to make any significant payment of cash taxes through 2012. However, upon receipt of the reassessment for 2007, an amount of about $27 million became payable and was remitted in January 2013. See note 24 to the financial statements.

Outlook for 2013

We have contractual arrangements to sell uranium produced at our Canadian mining operations to a trading and marketing company located in a foreign jurisdiction. These arrangements reflect the uranium markets at the time they were signed, with the risk and benefit of subsequent movements in uranium prices accruing to the foreign trading and marketing company.

On an adjusted net earnings basis, we expect a recovery of 15% to 20% in 2013 from our uranium, fuel services and electricity segments, as taxable income in Canada is expected to decline. Subject to our success in the litigation with CRA, we expect our tax rate to continue in accordance with the 2013 outlook until the contractual arrangements noted above expire in 2016. As these arrangements expire and are replaced by new contracts that reflect the uranium market at the time of signing, our tax expense is expected to rise over time.

FOREIGN EXCHANGE

The exchange rate between the Canadian dollar and US dollar affects the financial results of our uranium and fuel services segments.

Sales of uranium and fuel services are routinely denominated in US dollars, while production costs are largely denominated in Canadian dollars. We use planned hedging to try to protect net inflows (total uranium and fuel services sales less US dollar cash expenses and product purchases) from the uranium and fuel services segments against declines in the US dollar in the shorter term. Our strategy is to hedge net inflows over a rolling 60-month period. Our policy is to hedge 35% to 100% of net inflows in the first 12 months. The range declines every year until it reaches 0% to 10% of our net inflows (from 48 and 60 months).

38 CAMECO CORPORATION

We also have a natural hedge against US currency fluctuations as a portion of our annual cash outlays, including purchases of uranium and fuel services, are denominated in US dollars. The earnings impact of this natural hedge is more difficult to identify because inventory includes material added over more than one fiscal period.

At December 31, 2012:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $0.99(Cdn), down from $1.00 (US) for $1.02 (Cdn) at December 31, 2011. The exchange rate averaged $1.00 (US) for $1.00 (Cdn) over the year.

• Our effective exchange rate for the year was about $1.00 (US) for $1.00 (Cdn), the same as in 2011.

• We had foreign currency forward contracts of $1.4 billion (US),EUR 110 million, AUD 20 million and an option to buy EUR 105 million at December 31, 2012. The US currency contracts had an average exchange rate of $1.00 (US) for $1.01 (Cdn).

• The mark-to-market gain on all foreign exchange contracts was $15 million compared to an $18 million loss at December 31, 2011.

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2012, all counterparties to foreign exchange hedging contracts had a Standard & Poor’s (S&P) credit rating of A or better.

Sensitivity analysis

At December 31, 2012, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2013 net earnings by about $10 million (Cdn). This sensitivity is based on an exchange rate of $1.00 (US) for $1.00 (Cdn).

MANAGEMENT’S DISCUSSION AND ANALYSIS 39

Outlook for 2013

Over the next several years, we expect to invest significantly in expanding production at existing mines and advancing projects, subject to market conditions, as we pursue our growth strategy. The projects are at various stages of development, from exploration and evaluation to construction.

We expect our existing cash balances and operating cash flows will meet our anticipated 2013 capital requirements without the need for significant additional funding. Cash balances will decline as we use the funds in our business and pursue our growth plans.

Our outlook for 2013 reflects the growth expenditures necessary to help us achieve our strategy. We do not provide an outlook for the items in the table that are marked with a dash.

See 2012 Financial results by segment on page 47 for details.

2013 FINANCIAL OUTLOOK

BPLP is not included in consolidated amounts due to a change in accounting (see page 36). NUKEM is also excluded (see page 52 for more information).

	CONSOLIDATED	URANIUM	FUEL SERVICES	ELECTRICITY
Production	—	23.3 million lbs	14 to 15 million kgU	—
Sales volume	—	31 to 33 million lbs	Increase 0% to 5%	—
Capacity factor	—	—	—	88%
Revenue compared to 2012	Increase 0% to 5%	Increase 0% to 5%1	Increase 5% to 10%	Decrease 5% to 10%
Average unit cost of sales (including D&A)	—	Increase 0% to 5%2	Decrease 0% to 5%	Increase 25% to 30%
Direct administration costs compared to 20123	Decrease 0% to 5%	—	—	—
Exploration costs compared to 2012	—	Decrease 5% to 10%	—	—
Tax rate	Recovery of 15% to 20%	—	—	—
Capital expenditures	$655 million4	—	—	$93 million (our share)

¹  Based on a uranium spot price of $43.65(US) per pound (the Ux spot price as of February 4, 2013), a long-term price indicator of $56.00 (US) per pound (the Ux long-term indicator on January 28, 2013) 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 2013 then we expect the overall unit cost of product sold to increase further.

³  Direct administration costs do not include stock-based compensation expenses. See page 36 for more information.

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

FIRST QUARTER 2013

It is not our practice to provide earnings outlook. However, due to a combination of factors expected to occur in the first quarter, we have determined it appropriate to provide some outlook for investors regarding our current expectations for our first quarter earnings.

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns, sales volumes and revenue, can vary significantly. We expect our uranium deliveries for the first quarter will be in the range of 5 million to 6 million pounds, down considerably from the 8 million reported in the first three months of 2012. Uranium sales for the balance of 2013 are expected to be more heavily weighted (~60%) to the second half of the year. However, not all delivery notices have been received to date, which could alter the delivery pattern. Typically, we receive notices six months in advance of the requested delivery date.

40 CAMECO CORPORATION

In addition, BPLP has outages scheduled for three of its four units in the first three months of 2013. Accordingly, we expect electricity generation to be significantly lower in the first quarter of 2013 than it was in the first quarter of 2012. The capacity factor is likely to be in the range of 75% to 80% and it is probable BPLP will report an operating loss for the quarter.

As a result, we expect our adjusted net earnings for the first quarter of 2013 will be significantly lower than the $124 million ($0.31 per share) in the first quarter of 2012. We do not believe that these factors will continue to have an impact on our adjusted net earnings for subsequent quarters of 2013. The guidance we have provided in the outlook table reflects our current expectations for the full year. We also expect our net earnings attributable to equity holders will be similarly impacted.

SENSITIVITY ANALYSIS

For 2013:

• a change of $5 (US) per pound in each of the Ux spot price ($43.65 (US) per pound on February 4, 2013) and the Ux long-term price indicator ($56.00 (US) per pound on January 28, 2013) would change revenue by $77 million and net earnings by $44 million

• a change of $5/MWh in the electricity spot price would change our 2013 net earnings by $2 million based on the assumption that the spot price will remain below the floor price of $51.62/MWh provided for under BPLP’s agreement with the Ontario Power Authority (OPA)

Liquidity and capital resources

At the end of 2012, we had cash and short-term investments of $799 million in a mix of short-term deposits and treasury bills, while our total debt amounted to $1.5 billion.

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 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.

FINANCIAL CONDITION

	2012			2011
Cash position ($ millions)		799			1,202
(cash, cash equivalents, short-term investments)
Cash provided by operations ($ millions)		644			745
(net cash flow generated by our operating activities after changes in working capital)
Cash provided by operations/net debt		88	%		n/a	1
(net debt is total consolidated debt, less cash position)
Net debt/total capitalization		12	%		n/a	1
(total capitalization is total long-term debt and equity)

¹  Cash and cash equivalents exceeded debt.

MANAGEMENT’S DISCUSSION AND ANALYSIS 41

CREDIT RATINGS

The credit ratings assigned to our securities by external ratings agencies are important to our ability to raise capital at competitive pricing to support our business operations. Our investment grade credit ratings reflect the current financial strength of our company.

Third-party ratings for our commercial paper and senior debt as of December 31, 2012:

SECURITY	DBRS		S&P
Commercial paper		R-1 (low)		A-1 (low)	1
Senior unsecured debentures		A (low)		BBB+

¹  Canadian National Scale Rating. The Global Scale Rating is A-2.

The rating agencies may revise or withdraw these ratings if they believe circumstances warrant. A change in our credit ratings could affect our cost of funding and our access to capital through the capital markets.

Liquidity

($ MILLIONS)	2012			2011
Cash, cash equivalents and short term investments at beginning of year		1202			1,258
Cash from operations		644			745
Investment activities
Additions to property, plant and equipment and acquisitions		(1,310	)		(647	)
Other investing activities		(23	)		40
Financing activities
Change in debt		492			(3	)
Interest paid		(54	)		(61	)
Issue of shares		7			7
Dividends		(158	)		(146	)
Exchange rate on changes on foreign currency cash balances		(1	)		9
Cash, cash equivalents and short term investments at end of year		799			1,202

Cash from operations

Cash from operations was 14% lower than in 2011 mainly due to lower profits in the uranium business and higher working capital requirements relating to increased inventory levels. Not including working capital requirements, our operating cash flows in the year were down $143 million. See note 26 to the financial statements.

Investing activities

Cash used in investing includes acquisitions and capital spending.

ACQUISITIONS AND DIVESTITURES

In 2012, we concluded the acquisition of the Yeelirrie deposit in Western Australia for a total cost of $454 million (US) (including $1.5 million in acquisition costs). In the second quarter, we acquired an additional interest in the Millennium project at a cost of $150 million. On January 9, 2013 we completed the acquisition of NUKEM by paying a total of $140 million (US) and assuming its net debt of $111 million (US). In 2011, we concluded no significant acquisitions or divestitures.

CAPITAL SPENDING

Starting in 2013, we are classifying capital spending as sustaining, capacity replacement or growth. As a mining company, sustaining capital is the money we spend to keep our facilities running in their present state, which would follow a gradually decreasing production curve, while capacity replacement capital is spent to maintain current production levels at those operations. Growth capital is money we invest to generate incremental production, and for business development. Previously, we categorized our capital spending as either sustaining (which included capacity replacement projects) or growth.

42 CAMECO CORPORATION

(CAMECO’S SHARE IN $ MILLIONS)	2012 PLAN			2012 ACTUAL
Growth capital
Cigar Lake		215			231
Inkai		10			9
McArthur River		35			32
Millennium		5			9
US ISR		30			48
Total growth capital		295			329
Sustaining capital
McArthur River/Key Lake		145			154
US ISR		50			26
Rabbit Lake		75			77
Inkai		30			15
Fuel services		20			15
Other		5			15
Total sustaining capital		325			302
Talvivaara		—			41
Total uranium & fuel services		620	1		672
Electricity (our 31.6% share of BPLP)		80			62

¹  We updated our 2012 capital cost estimate in the Q2 MD&A to $680 million and in the Q3 MD&A to $730 million.

Capital expenditures were 5% above our 2012 plan, mainly due to variances at Cigar Lake caused by a change in the timing of expenditures and increased costs.

OUTLOOK FOR INVESTING ACTIVITIES

(CAMECO’S SHARE IN $ MILLIONS)	2013 PLAN		2014 PLAN		2015 PLAN
Total uranium & fuel services		650		600-650		550-600
Sustaining capital		200		300-320		290-310
Growth capital		310		175-190		140-155
Capacity replacement capital		140		125-140		120-135
Talvivaara		5
Total uranium & fuel services		655
Electricity (our 31.6% share of BPLP)		93

We expect total capital expenditures for uranium and fuel services to decrease by about 1% in 2013.

Major sustaining, capacity replacement and growth expenditures in 2013 include:

• McArthur River/Key Lake – At McArthur River, the largest component is mine development at about $50 million. Other projects include upgrade of electrical infrastructure at about $40 million, as well as other site facility expansion and equipment purchases. At Key Lake, various projects to revitalize the mill will be undertaken at about $30 million, as well as upgrades to site electrical services and work on the tailings facilities.

• US in situ recovery (ISR) – Wellfield construction and well installation is the largest project at approximately $40 million. We also plan to continue work on the development of the North Butte project and revitalization of the processing plant.

• Rabbit Lake – At Eagle Point, the largest project includes mine development at about $15 million. Other projects include work on electrical systems, various mill equipment replacements and continued work on mine dewatering systems and tailings facilities.

MANAGEMENT’S DISCUSSION AND ANALYSIS 43

• Cigar Lake – In order to bring Cigar Lake into production in 2013, we estimate our share of capital expenditures will be about $182 million, including $27 million on modifications to the McClean Lake mill.

Our growth capital expenditures are related to our strategy to increase annual supply to 36 million pounds by 2018 and maintain the ability to respond quickly to changing market signals. The mix of projects and their underlying capital estimates could change significantly.

This information regarding currently expected capital expenditures for future periods is forward-looking information, and is based upon the assumptions and subject to the material risks discussed on pages 3 and 4. Our actual capital expenditures for future periods may be significantly different.

Financing activities

Cash from financing includes borrowing and repaying debt, and other financial transactions including paying dividends and providing financial assurance.

LONG-TERM CONTRACTUAL OBLIGATIONS

DECEMBER 31, 2012 ($ MILLIONS)	2013		2014 AND 2015		2016 AND 2017		2018 AND BEYOND		TOTAL
Long-term debt		16		339		48		1,028		1,431
Interest on long-term debt		71		140		105		260		576
Provision for reclamation		16		32		54		596		698
Provision for waste disposal		3		6		8		—		17
Other liabilities		—		—		—		586		586
Total		106		517		215		2,470		3,308

We have unsecured lines of credit of about $1.9 billion, which include the following:

• A $1.25 billion unsecured revolving credit facility that matures November 1, 2017. Each year on the anniversary date, and upon mutual agreement, the facility can be extended for an additional year. In addition to borrowing directly from this facility, we can use up to $100 million of it to issue letters of credit and we may use it to provide liquidity for our commercial paper program, as necessary. We may increase the revolving credit facility above $1.25 billion, by increments of no less than $50 million, up to a total of $1.75 billion. The facility ranks equally with all of our other senior debt. At December 31, 2012, there was nothing outstanding under this facility.

• Approximately $700 million in short-term borrowing and letters of credit provided by various financial institutions. We use these facilities mainly to provide financial assurance for future decommissioning and reclamation of our operating sites, and as overdraft protection. At December 31, 2012, we had approximately $672 million outstanding in letters of credit.

In the fourth quarter, we issued $400 million in Series E Debentures bearing interest at 3.75% per year, maturing on November 14, 2022 as well as $100 million in Series F Debentures bearing interest at 5.09% per year, maturing on November 14, 2042.

In total, we have $1.3 billion in senior unsecured debentures outstanding:

• $300 million bearing interest at 4.7% per year, maturing on September 16, 2015

• $500 million bearing interest at 5.67% per year, maturing on September 2, 2019

• $400 million bearing interest at 3.75% per year, maturing on November 14, 2022

• $100 million bearing interest at 5.09% per year, maturing on November 14, 2042

We have issued a $73 million (US) promissory note to GLE to support future development of its business. As of December 31, 2012, GLE requested drawings of $31 million (US) in principal and $7.7 million (US) in interest. The balance remaining on the note is $42 million (US).

44 CAMECO CORPORATION

DEBT COVENANTS

Our revolving credit facility includes the following financial covenants:

• our funded debt to tangible net worth ratio must be 1:1 or less

• other customary covenants and events of default

Funded debt is total consolidated debt less the following: non-recourse debt, $100 million in letters of credit, cash and short-term investments.

Not complying with any of these covenants could result in accelerated payment and termination of our revolving credit facility. At December 31, 2012, we complied with all covenants, and we expect to continue to comply in 2013.

Off-balance sheet arrangements

We had two kinds of off-balance sheet arrangements at the end of 2012:

• purchase commitments

• financial assurances

PURCHASE COMMITMENTS

DECEMBER 31, 2012 ($ MILLIONS)	2013		2014 AND 2015		2016 AND 2017		2018 AND BEYOND		TOTAL
Purchase commitments1		436		216		92		476		1,220

¹  Denominated in US dollars, converted to Canadian dollars as of December 31, 2012 at the rate of $1.00.

Most of these are commitments to buy uranium and fuel services products under long-term, fixed-price arrangements.

At the end of 2012, we had committed to $1.2 billion (Cdn) for the following:

• Approximately 25 million pounds of U₃O₈ equivalent from 2013 to 2027. Of these, about 10 million pounds are from our agreement with Techsnabexport Joint Stock Company (Tenex) to buy uranium from dismantled Russian weapons (the Russian HEU commercial agreement) through 2013.

• Approximately 23 million kgU as UF₆ in conversion services from 2013 to 2016 primarily under our agreements with Springfields Fuels Ltd. (SFL) and Tenex.

• Over 0.7 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-western supplier.

Non-delivery by Tenex or SFL under their agreements could have a material adverse effect on our financial condition, liquidity and results of operations.

Tenex, SFL and the SWU supplier do not have the right to terminate their agreements other than pursuant to customary event of default provisions.

MANAGEMENT’S DISCUSSION AND ANALYSIS 45

FINANCIAL ASSURANCES

DECEMBER 31 ($ MILLIONS)	2012		2011		CHANGE
Standby letters of credit		672		665		1	%
BPLP guarantees		59		69		(14	)%
Total		731		734		—

Standby letters of credit mainly provide financial assurance for the decommissioning and reclamation of our mining and conversion facilities. We are required to provide letters of credit to various regulatory agencies until decommissioning and reclamation activities are complete. Letters of credit are issued by financial institutions for a one-year term.

Our total commitment for financial guarantees on behalf of BPLP was an estimated $63 million at the end of the year. See note 31 to the financial statements.

Balance sheet

DECEMBER 31 ($ MILLIONS EXCEPT PER SHARE AMOUNTS)	2012		2011		2010		CHANGE FROM 2011 TO 2012
Inventory		564		494		533		14	%
Total assets		8,215		7,616		7,021		8	%
Long-term financial liabilities		2,249		1,736		1,524		30	%
Dividends per common share		0.40		0.40		0.28		—

Total product inventories increased by 14% to $564 million this year due to higher levels of inventory for uranium and fuel services, where the quantities sold were lower than the quantities produced and purchased for the year. The average cost of uranium was higher as a result of the increasing costs of produced and purchased material. At December 31, 2012, our average cost for uranium was $27.35 per pound, up from $25.11 per pound at December 31, 2011. In 2011, total product inventories decreased by 7% due to lower levels of uranium, where the quantities sold exceeded quantities produced and purchased for the year.

At the end of 2012, our total assets amounted to $8.2 billion, an increase of $0.6 billion compared to 2011 due primarily to acquisitions of uranium properties in the year. In 2011, the total asset balance increased by $0.6 billion due primarily to a higher rate of investment in property, plant and equipment.

The major components of long-term financial liabilities are long-term debt, finance lease obligations, the provision for reclamation and financial derivatives. In 2012, our balance increased by $0.5 billion. In 2011, our balance increased by $0.2 billion.

46 CAMECO CORPORATION

2012 financial results by segment

Uranium

HIGHLIGHTS	2012		2011		CHANGE
Production volume (million lbs)		21.9		22.4		(2	)%
Sales volume (million lbs)		32.5		32.9		(1	)%
Average spot price ($US/lb)		48.40		56.36		(14	)%
Average long-term price ($US/lb)		60.13		66.79		(10	)%
Average realized price
($US/lb)		47.62		49.17		(3	)%
($Cdn/lb)		47.61		49.18		(3	)%
Average unit cost of sales ($Cdn/lb) (including D&A)		32.09		29.94		7	%
Revenue ($ millions)		1,546		1,616		(4	)%
Gross profit ($ millions)		504		632		(20	)%
Gross profit (%)		33		39		(15	)%

Production volumes in 2012 were 2% lower than 2011 due to lower production from Smith Ranch-Highland and McArthur River/Key Lake, which had record production in 2011. See Uranium – production overview on page 64 for more information.

Uranium revenues this year were down 4% compared to 2011, due to a slight decrease in sales volumes and a decrease of 3% in the Canadian dollar average realized price. Our realized prices this year in US dollars were 3% lower than 2011 mainly due to lower US dollar prices under market-related contracts. The spot price for uranium averaged $48.40 in 2012, a decline of 14% compared to the 2011 average price of $56.36. Total cost of sales (including D&A) increased by 6% this year ($1.0 billion compared to $984 million in 2011). This was mainly the result of the following:

• average unit costs for produced uranium were 13% higher and average unit costs for purchased uranium were 9% higher due to an increase in spot purchases

• lower royalty charges in 2012 due mainly to the decline in the realized price. In 2012, total royalties were $116 million compared to $124 million in 2011.

The net effect was a $128 million decrease in gross profit for the year.

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)	2012		2011		CHANGE
Produced
Cash cost		19.95		18.45		8	%
Non-cash cost		8.13		6.50		25	%
Total production cost		28.08		24.95		13	%
Quantity produced (million lbs)		21.9		22.4		(2	)%
Purchased
Cash cost		28.50		26.08		9	%
Quantity purchased (million lbs)		11.2		9.6		17	%
Totals
Produced and purchased costs		28.22		25.29		12	%
Quantities produced and purchased (million lbs)		33.1		32.0		3	%

MANAGEMENT’S DISCUSSION AND ANALYSIS 47

Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. These measures do not have a standardized meaning or a consistent basis of calculation under IFRS. We use these measures in our assessment of the performance of our uranium business. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance and ability to generate cash flow.

These measures are non-standard supplemental information and should not be considered in isolation or as a substitute for measures of performance prepared according to accounting standards. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS. Other companies may calculate these measures differently so you may not be able to make a direct comparison to similar measures presented by other companies.

To facilitate a better understanding of these measures, the table below presents a reconciliation of these measures to our unit cost of sales for the years ended 2012 and 2011 as reported in our financial statements.

CASH AND TOTAL COST PER POUND RECONCILIATION

($ MILLIONS)	2012			2011
Cost of product sold		871.3			824.3
Add / (subtract)
Royalties		(116.0	)		(123.6	)
Standby charges		(28.6	)		(22.0	)
Other selling costs		(6.2	)		(9.4	)
Change in inventories		35.6			(5.7	)
Cash operating costs (a)		756.1			663.6
Add / (subtract)
Depreciation and amortization		170.9			159.2
Change in inventories		7.2			(13.6	)
Total operating costs (b)		934.2			809.2
Uranium produced and purchased (millions lbs) (c)		33.1			32.0
Cash costs per pound (a ÷ c)		22.84			20.74
Total costs per pound (b ÷ c)		28.22			25.29

OUTLOOK FOR 2013

We expect to produce 23.3 million pounds in 2013 and have commitments under long-term contracts to purchase 12 million pounds.

Based on the contracts we have in place, we expect to sell between 31 million and 33 million pounds of U₃O₈ in 2013. We expect the unit cost of sales to be up to 5% higher than in 2012. The increase is due primarily to higher costs for produced material. If we decide to make additional discretionary purchases in 2013, then we expect the overall unit cost of sales to increase further.

Based on current spot prices, revenue should be up to 5% higher than it was in 2012 as a result of an expected increase in the realized price.

PRICE SENSITIVITY ANALYSIS: URANIUM

The table and graph below are not forecasts of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table and graph. They are designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2012 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 December 31, 2012, and none of the assumptions we list below change.

48 CAMECO CORPORATION

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

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)

SPOT PRICES ($US/lb U3O8)	$20		$40		$60		$80		$100		$120		$140
2013		43		46		53		61		69		77		83
2014		45		48		56		64		73		82		89
2015		41		46		56		66		76		86		95
2016		43		48		58		69		80		90		98
2017		42		47		57		67		78		87		95

The table and graph illustrate the mix of long-term contracts in our December 31, 2012 portfolio, and are consistent with our contracting strategy. Both have been updated to December 31, 2012 to reflect:

• deliveries made and contracts entered into up to December 31, 2012

• our best estimate of future deliveries

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. In 2012, a number of older contracts expired 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 2013

Inflation

• is 2% per year

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 15% 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 49

TIERED ROYALTIES

As sales of material we produce at our Saskatchewan properties increase, so do the tiered royalties we pay. The table below indicates what we would pay in tiered royalties at various realized prices. We record tiered royalties as a cost of sales.

This table assumes that we sell 100,000 pounds U₃O₈ and that there is no capital allowance available to reduce royalties, and is based on 2012 government prescribed rates. The index value to calculate rates for 2013 is not available until April 2013.

REALIZED PRICE ($Cdn)	TIER 1 ROYALTY 6% X (SALES PRICE—$18.66)		TIER 2 ROYALTY 4% X (SALES PRICE—$28.00)		TIER 3 ROYALTY 5%  X (SALES PRICE—$37.33)		TOTAL ROYALTIES
25		38,040		—		—		38,040
35		98,040		28,000		—		126,040
45		158,040		68,000		38,350		264,390
55		218,040		108,000		88,350		414,390
65		278,040		148,000		138,350		564,390
75		338,040		188,000		188,350		714,390
85		398,040		228,000		238,350		864,390

50 CAMECO CORPORATION

Fuel services

(Includes results for UF₆, UO₂ and fuel fabrication)

HIGHLIGHTS	2012		2011		CHANGE
Production volume (million kgU)		14.2		14.7		(3	)%
Sales volume (million kgU)		16.1		18.3		(12	)%
Realized price ($Cdn/kgU)		17.24		16.71		3	%
Average unit cost of sales ($Cdn/kgU) (including D&A)		14.63		13.75		6	%
Revenue ($ millions)		277		305		(9	)%
Gross profit ($ millions)		42		54		(22	)%
Gross profit (%)		15		18		(17	)%

Total revenue decreased by 9% due to a 12% decrease in sales volumes. We set lower sales target in 2012 due to weak market conditions at the beginning of the year.

The total cost of products and services sold (including D&A) decreased by 6% ($235 million compared to $251 million in 2011) due to the decrease in sales volumes. The average unit cost of sales was 6% higher due to higher unit costs for UF₆ relating to lower production.

The net effect was a $12 million decrease in gross profit.

OUTLOOK FOR 2013

In 2013, we plan to produce 14 million to 15 million kgU, and we expect sales volumes to be up to 5% higher than in 2012. Overall revenue is expected to increase by 5% to 10%, as a result of the higher volumes and an expected increase in the average realized price. We expect the unit cost of product sold (including D&A) to decrease by 0% to 5%, therefore overall gross profit will increase as a result.

MANAGEMENT’S DISCUSSION AND ANALYSIS 51

NUKEM

On January 9, 2013, we completed the acquisition of NUKEM GmbH (NUKEM) from Advent International (Advent) and other shareholders. NUKEM is one of the world’s leading traders and brokers of nuclear fuel products and services.

NUKEM was acquired for cash consideration of €107 million ($140 million (US)), plus closing adjustments. We also assumed NUKEM’s net debt which amounted to about €84 million ($111 million (US)) on January 9, 2013. Acquisition related costs of $4 million have been expensed and included in administration expense in the consolidated statement of earnings. We received the economic benefits of owning NUKEM as of January 1, 2012, however, in accordance with accounting requirements, our financial reporting will reflect results from January 9, 2013 forward.

The purchase agreement also includes an earn-out provision that could provide Advent with a share of NUKEM’s earnings under certain conditions for the years 2012 through 2014. The earn-out is based on NUKEM exceeding certain minimum threshold levels of EBITDA, as specified and defined in the purchase agreement. The EBITDA is derived from NUKEM’s audited financial statements and the earn-out payment to Advent is paid in the following year. For 2012, we estimate the earn-out amount will be about $5 million (US).

For accounting purposes, the purchase price is allocated to the assets and liabilities acquired based on their fair values as of the acquisition date (January 9, 2013). As the acquisition has closed very recently, we have not yet finalized the allocation of the purchase price. However, we expect that the majority of the purchase price will be allocated to the purchase and sales contracts acquired, nuclear fuel inventories, and goodwill.

OUTLOOK FOR 2013

The requirement to assign fair values to the sales and purchase contracts as of the acquisition date will impact the future operating results reported for NUKEM. For example, NUKEM is a party to the Russian HEU commercial agreement, which provides for the purchase of uranium at a price well below the current market. We will assign a portion of the purchase price to this contract. Our future cost of sales will reflect the amortization of the value assigned to the contract in the periods in which this HEU material is delivered. This accounting will be applied to all contracts in the portfolio as of the acquisition date. As a result, we expect the profit margins we report for NUKEM will be in the range of 3% to 5% in 2013. We plan to report NUKEM as a separate business segment.

For 2013, NUKEM expects to deliver approximately 9 million to 11 million pounds of uranium and about 500,000 SWU, resulting in total revenues in the range of $500 million to $600 million. NUKEM expects to incur costs for administration in the range of $10 million to $12 million. The effective income tax rate is expected to be in the range of 30% to 35%. Operating cash flows are expected to be in the range of $100 million to $125 million.

52 CAMECO CORPORATION

Electricity

BPLP

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

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	2012			2011			CHANGE
Output—terawatt hours (TWh)		26.8			24.9			8	%
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		94	%		87	%		8	%
Realized price ($/MWh)		55	1		54	2		2	%
Average Ontario electricity spot price ($/MWh)		23			30			(23	)%
Revenue		1,487			1,354			10	%
Operating costs (net of cost recoveries)		889			1,006			(12	)%
Cash costs		669			812			(18	)%
Non-cash costs		220			194			13	%
Income before interest and finance charges		598			348			72	%
Interest and finance charges		26			37			(30	)%
Cash from operations		543			490			11	%
Capital expenditures		194			243			(20	)%
Distributions		425			270			57	%
Capital calls		63			21			200	%
Operating costs ($/MWh)		33	1		40	2		(18	)%

¹ Based on actual generation of 26.8 TWh plus deemed generation of 0.4 TWh

² Based on actual generation of 24.9 TWh plus deemed generation of 0.4 TWh

OUR EARNINGS FROM BPLP

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	2012			2011			CHANGE
BPLP’s earnings before taxes (100%)		572			311			84	%
Cameco’s share of pretax earnings before adjustments (31.6%)		181			98			85	%
Proprietary adjustments		(6	)		(6	)		—
Earnings before taxes from BPLP		175			92			90	%

BPLP’s increased results in 2012 when compared to 2011 are partially the result of revenues being 10% higher than in 2011 due to a 2% increase in realized electricity prices. BPLP’s average realized price reflects spot sales, revenue recognized under BPLP’s agreement with the Ontario Power Authority (OPA) and revenue from financial contracts.

BPLP has an agreement with the OPA under which output from each B reactor is supported by a floor price (currently $51.62/MWh) that is adjusted annually for inflation. The floor price mechanism and any associated payments to BPLP for the output from each individual B reactor will expire on a date specified in the agreement. The expiry dates are December 31, 2015 for unit B6, December 31, 2016 for unit B5, December 31, 2017 for unit B7 and December 31, 2019 for unit B8. Revenue is recognized monthly, based on the positive difference between the floor price and the spot price. BPLP does not have to repay the revenue from the agreement with the OPA to the extent that the floor price for the particular year exceeds the average spot price for that year.

The agreement also provides for payment if the Independent Electricity System Operator (IESO) reduces BPLP’s generation because Ontario’s baseload generation supply is higher than required. The amount of the reduction is considered ‘deemed generation’, for which BPLP is paid either the spot price or the floor price—whichever is higher. The deemed generation approach has provided the IESO with significant flexibility in dealing with changes to the Ontario electricity market in recent years. Deemed generation was 0.4 TWh in 2012, the same as in 2011.

MANAGEMENT’S DISCUSSION AND ANALYSIS 53

During 2012, BPLP recognized revenue of $773 million under the agreement with the OPA, compared to $498 million in 2011.

BPLP also has financial contracts in place that reflect market conditions at the time they were signed. BPLP receives or pays the difference between the contract price and the spot price. BPLP sold the equivalent of about 64% of its output under financial contracts in 2012, compared to 54% in 2011. From time to time, BPLP enters the market to lock in gains under these contracts. Gains on BPLP’s contracting activity were slightly higher than in 2011.

In addition, BPLP’s increased results in 2012 when compared to 2011 were also partially the result of lower operating costs. BPLP’s operating costs were $889 million this year compared to $1.0 billion in 2011 due to lower supplemental lease payments and lower maintenance costs incurred during outage periods.

The net effect was an increase in our share of earnings before taxes of 90%.

BPLP distributed $425 million to the partners in 2012. Our share was $134 million. BPLP capital calls to the partners in 2012 were $63 million. Our share was $20 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

BPLP’s capacity factor was 94% in 2012, up from 87% in 2011 due to a lower volume of outage days during the year’s planned outages compared to last year’s planned outages.

OUTLOOK FOR 2013

Bruce Power estimates the average capacity factor for the four Bruce B reactors to be 88% in 2013, and actual output to be about 5% to 10% lower than it was in 2012 due to more planned outage days in 2013. The 2013 realized price for electricity is projected to be slightly lower than 2012. As a result we expect that revenue will decrease by about 5% to 10%.

We expect the average unit cost (net of cost recoveries) to be 25% to 30% higher in 2013 and total operating costs to increase by about 15% to 20%, mainly due to more planned outages resulting in higher costs.

In 2013, we will account for our interest in BPLP using equity accounting.

54 CAMECO CORPORATION

Fourth quarter results

Fourth quarter consolidated results

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED DECEMBER  31				CHANGE
	2012		2011
Revenue		958		971		(1	)%
Gross profit		307		353		(13	)%
Net earnings attributable to equity holders		45		265		(83	)%
$ per common share (basic)		0.11		0.67		(84	)%
$ per common share (diluted)		0.11		0.67		(84	)%
Adjusted net earnings (non-IFRS, see page 34)		237		249		(5	)%
$ per common share (adjusted and diluted)		0.60		0.63		(5	)%
Cash provided by operations (after working capital changes)		283		258		10	%

In the fourth quarter of 2012, our net earnings attributable to equity holders (net earnings) were $45 million ($0.11 per share diluted), a decrease of $220 million compared to $265 million ($0.67 per share diluted) in 2011. This decline was largely the result of the $168 million write-down of our interest in the Kintyre project and lower earnings from our uranium business, partially offset by stronger results in the electricity business. Uranium profits were impacted by a 7% decline in the average realized selling price due mainly to a lower spot price compared to the fourth quarter of 2011. Earnings in the electricity business improved as a result of higher generation and lower operating costs.

The 5% decrease in adjusted net earnings in the quarter followed the same trend as our net earnings, due to lower results in our uranium business, partially offset by the results in our electricity business.

We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our financial performance from period to period. See page 34 for more information. The table below reconciles adjusted net earnings with our net earnings.

($ MILLIONS)	THREE MONTHS ENDED DECEMBER 31
	2012			2011
Net earnings attributable to equity holders		45			265
Adjustments
Adjustments on derivatives1 (pre-tax)		33			(22	)
Income taxes on adjustments to derivatives		(9	)		6
Impairment charge on non-producing property		168			—
Adjusted net earnings		237			249

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.

We recorded an income tax recovery of $5 million this quarter, based on adjusted net earnings, compared to a $25 million expense in 2011.

Direct administration costs were $53 million in the quarter, $7 million higher than the same period last year. Stock-based compensation expenses were $1 million lower than the fourth quarter of 2011. See note 27 to the financial statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS 55

($ MILLIONS)	THREE MONTHS ENDED DECEMBER 31				CHANGE
	2012		2011
Direct administration		53		46		15	%
Stock-based compensation		4		5		(20	)%
Total administration		57		51		12	%

Quarterly trends

HIGHLIGHTS ($ MILLIONS EXCEPT PER SHARE AMOUNTS)	2012									2011
	Q4		Q3		Q2			Q1		Q4		Q3		Q2		Q1
Revenue		958		408		391			564		971		527		425		461
Net earnings attributable to equity holders		45		82		8			131		265		39		55		91
$ per common share (basic)		0.11		0.21		0.02			0.33		0.67		0.10		0.14		0.23
$ per common share (diluted)		0.11		0.21		0.02			0.33		0.67		0.10		0.14		0.23
Adjusted net earnings (non-IFRS, see page 34)		237		52		34			124		249		104		72		84
$ per common share (adjusted and diluted)		0.60		0.13		0.09			0.31		0.63		0.26		0.18		0.22
Cash provided by operations (after working capital changes)		283		44		(94	)		411		258		192		23		272

Key things to note:

• Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 74% of consolidated revenues in the fourth 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. More than 40% of our uranium deliveries for 2012 occurred in the fourth quarter.

• 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 34 for more information).

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

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

56 CAMECO CORPORATION

Fourth quarter results by segment

Uranium

HIGHLIGHTS	THREE MONTHS ENDED DECEMBER 31				CHANGE
	2012		2011
Production volume (million lbs)		6.5		6.6		(2	)%
Sales volume (million lbs)		14.4		13.8		4	%
Average spot price ($US/lb)		42.46		51.79		(18	)%
Average long-term price ($US/lb)		58.50		62.50		(6	)%
Average realized price
($US/lb)		49.97		52.09		(4	)%
($Cdn/lb)		49.37		53.08		(7	)%
Average unit cost of sales ($Cdn/lb) (including D&A)		32.88		30.29		9	%
Revenue ($ millions)		709		731		(3	)%
Gross profit ($ millions)		237		314		(25	)%
Gross profit (%)		33		43		(23	)%

Production volumes for the quarter decreased by 2% year over year. See Uranium – production overview on page 64 for more information.

Uranium revenues were down 3% due to a 7% decrease in the Canadian dollar average realized price, partially offset by a 4% increase in sales volumes.

Our realized prices this quarter were lower than the fourth quarter of 2011 mainly due to lower US dollar prices under market related contracts. In the fourth quarter of 2012, the uranium spot price averaged $42.46 (US), 18% lower than the $51.79 (US) in the fourth quarter of 2011.

Total cost of sales (including D&A) increased by 13% ($472 million compared to $417 million in 2011). This was mainly the result of the following:

• the 4% increase in sales volumes

• the 11% increase in average unit costs for produced uranium due to an increase in non-cash costs

• a 75% increase in the average unit costs for purchased uranium due to increased purchases at spot prices. In the fourth quarter of 2011, most of our purchases were under long-term contracts at more favourable fixed prices.

• lower royalty charges due to the lower realized price and reduced deliveries of Saskatchewan-produced material. In 2012, total royalty charges were $52 million compared to $61 million in 2011.

The net effect was a $77 million decrease in gross profit for the quarter.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 57

($Cdn/lb)	THREE MONTHS ENDED DECEMBER 31				CHANGE
	2012		2011
Produced
Cash cost		17.01		17.44		(2	)%
Non-cash cost		8.41		5.52		52	%
Total production cost		25.42		22.96		11	%
Quantity produced (million lbs)		6.5		6.6		(2	)%
Purchased
Cash cost		32.94		18.86		75	%
Quantity purchased (million lbs)		2.8		2.3		22	%
Totals
Produced and purchased costs		27.69		21.90		26	%
Quantities produced and purchased (million lbs)		9.3		8.9		4	%

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 fourth quarters of 2012 and 2011.

CASH AND TOTAL COST PER POUND RECONCILIATION

($ MILLIONS)	THREE MONTHS ENDED DECEMBER 31
	2012			2011
Cost of product sold		390.7			336.8
Add / (subtract)
Royalties		(51.7	)		(61.3	)
Standby charges		(7.7	)		(6.0	)
Other selling costs		(3.3	)		(2.8	)
Change in inventories		(125.2	)		(108.2	)
Cash operating costs (a)		202.8			158.5
Add / (subtract)
Depreciation and amortization		81.3			80.1
Change in inventories		(26.6	)		(43.7	)
Total operating costs (b)		257.5			194.9
Uranium produced & purchased (millions lbs) (c)		9.3			8.9
Cash costs per pound (a ÷ c)		21.81			17.81
Total costs per pound (b ÷ c)		27.69			21.90

58 CAMECO CORPORATION

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

HIGHLIGHTS	THREE MONTHS ENDED DECEMBER 31				CHANGE
	2012		2011
Production volume (million kgU)		3.3		3.1		6	%
Sales volume (million kgU)		5.9		7.2		(18	)%
Realized price ($Cdn/kgU)		16.70		14.67		14	%
Average unit cost of sales ($Cdn/kgU) (including D&A)		13.44		11.18		20	%
Revenue ($ millions)		99		106		(7	)%
Gross profit ($ millions)		19		25		(24	)%
Gross profit (%)		19		24		(21	)%

Total revenue decreased by 7% due to an 18% decrease in sales volumes, offset by a 14% increase in realized price.

The total cost of products and services sold (including D&A) decreased by 2% ($79 million compared to $81 million in the fourth quarter of 2011) due to the decrease in sales volumes, offset by an increase in the average unit cost of sales. When compared to 2011, the average unit cost of sales was 20% higher due to the mix of fuel services products sold and to higher cost recoveries being recorded in 2011.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 59

Electricity

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

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED DECEMBER 31						CHANGE
	2012			2011
Output—terawatt hours (TWh)		7.2			6.2			16	%
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		100	%		86	%		16	%
Realized price ($/MWh)		54			53	1		2	%
Average Ontario electricity spot price ($/MWh)		24			27			(11	)%
Revenue		392			338			16	%
Operating costs (net of cost recoveries)		221			271			(18	)%
Cash costs		165			220			(25	)%
Non-cash costs		56			51			10	%
Income before interest and finance charges		171			67			155	%
Interest and finance charges		6			7			(13	)%
Cash from operations		101			114			(11	)%
Capital expenditures		54			84			(36	)%
Distributions		140			65			115	%
Capital calls		14			10			40	%
Operating costs ($/MWh)		31			42	1		(26	)%

¹ Based on actual generation of 6.2 TWh plus deemed generation of 0.2 TWh in the fourth quarter.

OUR EARNINGS FROM BPLP

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED DECEMBER 31						CHANGE
	2012			2011
BPLP’s earnings before taxes (100%)		165			60			175	%
Cameco’s share of pretax earnings before adjustments (31.6%)		52			19			174	%
Proprietary adjustments		(2	)		(2	)		—
Earnings before taxes from BPLP		50			17			194	%

Total electricity revenue increased 16% due to higher output and slightly higher realized price. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA, and financial contract revenue. BPLP recognized revenue of $198 million this quarter under its agreement with the OPA, compared to $147 million in the fourth quarter of 2011. The equivalent of about 58% of BPLP’s output was sold under financial contracts this quarter, compared to 66% in the fourth quarter of 2011. From time to time BPLP enters the market to lock in gains under these contracts. Gains on BPLP’s contracting activity in the fourth quarter 2012 were similar to 2011.

The capacity factor was 100% this quarter, up from 86% in the fourth quarter of 2011. There were no outage days in the fourth quarter this year compared to a planned outage in 2011.

Operating costs were $221 million compared to $271 million in 2011 due to lower supplemental lease payments and lower maintenance costs incurred as a result of no outages in the fourth quarter.

The result was a 194% increase in our share of earnings before taxes.

BPLP distributed $140 million to the partners in the fourth quarter. Our share was $44 million. BPLP capital calls to the partners in the fourth quarter were $14 million. Our share was $4 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

60 CAMECO CORPORATION

Our operations and development projects

This section of our MD&A is an overview of each of our operations, what we accomplished this year, our plans for the future and how we manage risk.

	URANIUM
	Operating properties
66	McArthur River / Key Lake
72	Rabbit Lake
74	Smith Ranch-Highland
76	Crow Butte
77	Inkai
	Development project
81	Cigar Lake
	Projects under evaluation
86	Kintyre
88	Millennium
90	Yeelirrie
92	EXPLORATION
	FUEL SERVICES
	Refining
93	Blind River refinery
	Conversion and fuel manufacturing
94	Port Hope conversion services
94	Cameco fuel manufacturing
94	Springfields fuels
96	NUKEM Gmbh
	ELECTRICITY
97	Bruce Power Limited Partnership

MANAGEMENT’S DISCUSSION AND ANALYSIS 61

Managing the risks

The nature of our operations means we face many potential risks and hazards that could have a significant impact on our business. We have comprehensive systems and procedures in place to manage them, but there is no assurance we will be successful in preventing the harm any of these risks and hazards could cause.

Below we list the regulatory, environmental and operational risks that generally apply to all of our operations, development projects and projects under evaluation. We also talk about how we manage specific risks in each operation or project update. These risks could have a material impact on our business in the near term.

We recommend you also review our annual information form, which includes a discussion of other material risks that could have an impact on our business.

Regulatory risks

A significant part of our economic value depends on our ability to:

• obtain and renew the licences and other approvals we need to operate, to increase production at our mines and to develop new mines. If we do not receive the regulatory approvals we need, or do not receive them at the right time, then we may have to delay, modify or cancel a project, which could increase our costs and delay or prevent us from generating revenue from the project. Regulatory review, including the review of environmental matters, is a long and complex process.

• comply with the conditions in these licences and approvals. In a number of instances, our right to continue operating facilities, increase production at our mines and develop new mines depends on our compliance with these conditions.

• comply with the extensive and complex laws and regulations that govern our activities, including our growth plans. Environmental legislation imposes strict standards and controls on almost every aspect of our operations and the mines we plan to develop, and is not only introducing new requirements, but also becoming more stringent. For example:

• we must complete the environmental assessment process before we can begin developing a new mine or make any significant change to our operations

• we may need regulatory approval to make changes to our operational processes, which can take a significant amount of time because it may require an extensive review of supporting technical information. The complexity of this process can be further compounded when regulatory approvals are required from multiple agencies.

We use significant management and financial resources to manage our regulatory risks.

Environmental risks

We have the safety, health and environmental risks associated with any mining and chemical processing company. Our uranium, fuel services and electricity segments also face unique risks associated with radiation.

Laws to protect the environment are becoming more stringent for members of the nuclear energy industry and have inter-jurisdictional aspects (both federal and provincial/state regimes are applicable). Once we have permanently stopped mining and processing activities at an operating site, we are required to decommission the site to the satisfaction of the regulators. We have developed conceptual decommissioning plans for our operating sites and use them to estimate our decommissioning costs. Regulators review our detailed decommissioning plan on a regular basis and, as the site approaches or goes into decommissioning, carry out the required regulatory approval process. This can result in further regulatory process, as well as additional requirements, costs and financial assurances.

62 CAMECO CORPORATION

At the end of 2012, our estimate of total decommissioning and reclamation costs was $698 million. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $553 million at the end of 2012 (the present value of the $698 million). Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, our expected costs for decommissioning and reclamation for the next five years are not material. We are in the process of updating the preliminary decommissioning plans and cost estimates for Cigar Lake, McArthur River, Key Lake and Rabbit Lake, which will be reviewed by all of the regulatory authorities in 2013. As part of that process, we expect that the preliminary decommissioning cost estimates for these facilities will increase.

We provide financial assurances for decommissioning and reclamation such as letters of credit to regulatory authorities, as required. We had a total of $672 million in letters of credit supporting our reclamation liabilities at the end of 2012. All of our North American operations have letters of credit in place that provide financial assurance in connection with our preliminary plans for decommissioning for the sites.

Some of the sites we own or operate have been under ongoing investigation and/or remediation and planning as a result of historic soil and groundwater conditions. For example, we are addressing issues related to historic soil and groundwater contamination at Port Hope.

We use significant management and financial resources to manage our environmental risks.

We manage environmental risks through our safety, health, environment and quality (SHEQ) management system. Our chief executive officer is responsible for ensuring that our SHEQ management system is implemented. Our board’s safety, health and environment committee also oversees how we manage our environmental risks.

In 2012, we invested:

• $117 million in environmental protection, monitoring and assessment programs, or 19% more than 2011

• $30 million in health and safety programs, or about the same as 2011

Spending for health and safety programs in 2013 is expected to be similar to 2012, while spending for environmental programs is expected to decrease slightly.

Operational risks

Other operational risks and hazards include:

• environmental damage

• industrial and transportation accidents

• labour shortages, disputes or strikes

• cost increases for labour, contracted or purchased materials, supplies and services

• shortages of required materials, supplies and equipment

• transportation disruptions

• electrical power interruptions

• equipment failures

• non-compliance with laws and licences

• catastrophic accidents

• fires

• blockades or other acts of social or political activism

• natural phenomena, such as inclement weather conditions, floods and earthquakes

• unusual, unexpected or adverse mining or geological conditions

• underground floods

• ground movement or cave ins

• tailings pipeline or dam failures

• technological failure of mining methods.

We have insurance to cover some of these risks and hazards, but not all of them, and not to the full amount of losses or liabilities that could potentially arise.

MANAGEMENT’S DISCUSSION AND ANALYSIS 63

Uranium – production overview

URANIUM PRODUCTION

CAMECO’S SHARE	THREE MONTHS ENDED DECEMBER 31				YEAR ENDED DECEMBER 31
(MILLION lbs)	2012		2011		2012		2011		2012 PLAN
McArthur River/Key Lake		3.5		3.9		13.6		13.9		13.5	1
Rabbit Lake		1.7		1.6		3.8		3.8		3.7
Smith Ranch-Highland		0.3		0.2		1.1		1.4		1.3	1
Crow Butte		0.2		0.2		0.8		0.8		0.7
Inkai		0.8		0.7		2.6		2.5		2.5
Total		6.5		6.6		21.9		22.4		21.7	1

¹  We updated our initial 2012 plan for McArthur River/Key Lake (to 13.5 million pounds from 13.1 million pounds) and Smith Ranch-Highland (to 1.3 million pounds from 1.6 million pounds) in our Q3 MD&A.

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. We expect to purchase about 900,000 pounds of supply under our agreement with Talvivaara when all regulatory approvals are received, work on the extraction process is complete, and once they ramp up to full production. We expect production to start in the first half of 2014.

Cameco’s share of production – annual forecast to 2017

CURRENT FORECAST (MILLION lbs)	2013		2014		2015		2016		2017
McArthur River/Key Lake		13.2		13.1		13.1		13.1		13.1
Rabbit Lake		4.2		4.2		4.2		4.2		4.2
US ISR		2.6		2.9		2.9		3.0		3.0
Inkai1		2.9		2.9		2.9		2.9		2.9
Cigar Lake		0.3		1.8		5.5		7.9		8.2
Total share of production		23.2		24.9		28.6		31.1		31.4
Cameco’s share of Inkai’s production on which profits are generated2
Inkai1		3.0		3.0		3.0		3.0		3.0
Total2		23.3		25.0		28.7		31.2		31.5

¹ In 2011, we signed a memorandum of agreement (2011 MOA) with Kazatomprom to increase annual production to 5.2 million pounds (100% basis). Under the 2011 MOA, we will have 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.

Our 2013 and future annual production targets for Inkai assume, and we expect, that 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.

There is no certainty Inkai will receive these permits or approvals. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2013 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 3 and 4, and specifically on the assumptions and risks noted above and listed here. Actual production may be significantly different from this forecast.

64 CAMECO CORPORATION

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 65

Uranium – operating properties

	McArthur River/Key Lake McArthur River is the world’s largest, high-grade uranium mine, and Key Lake is the largest uranium mill in the world. Ore grades at the McArthur River mine are 100 times the world average, which means it can produce more than 18 million pounds per year by mining only 150 to 200 tonnes of ore per day. We are the operator. McArthur River is one of our three material uranium properties.
Location	Saskatchewan, Canada
Ownership	69.805% – McArthur River 83.33% – Key Lake
End product	Uranium concentrates
ISO certification	ISO 14001 certified
Mine type	Underground
Estimated reserves (our share)	264.5 million pounds (proven and probable), average grade U3O8: 16.36%
Estimated resources (our share)	8.5 million pounds (measured and indicated), average grade U3O8 : 5.65% 39.5 million pounds (inferred), average grade U3O8: 7.78%
Mining methods	Currently: raiseboring; Secondary (under development): blasthole stoping, Boxhole boring
Licenced capacity	Mine and mill: 18.7 million pounds per year (can be exceeded – see Production flexibility)
Total production: 2000 to 2012 (100% basis) 1983 to 2002	230.5 million pounds (McArthur River/Key Lake) 209.8 million pounds (Key Lake)
2012 production (our share)	13.6 million pounds
2013 forecast production (our share)	13.2 million pounds
Estimated decommissioning cost (100% basis)	$48 million – McArthur River (pending regulatory review) $225 million – Key Lake (pending regulatory review)

BACKGROUND

Production Flexibility

Our operating licences for the Key Lake mill and McArthur River mine were amended in 2009 and 2010, giving us flexibility in our annual licensed production limit. As long as average annual production does not exceed 18.7 million pounds per year, these amendments allow:

• the Key Lake mill to produce up to 20.4 million pounds (100% basis) per year

• the McArthur River mine to produce up to 21 million pounds (100% basis) per year

If production is lower than 18.7 million pounds in any year, we can produce more in future years until we recover the shortfall.

Mining methods and techniques

We use a number of innovative methods to mine the McArthur River deposit:

Ground freezing

The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. We use ground freezing to form an impermeable wall around the area being mined. This prevents water from entering the mine, and helps stabilize weak rock formations. To date, we have installed five freezewalls and are currently preparing a sixth.

66 CAMECO CORPORATION

Raisebore mining

Raisebore mining is an innovative non-entry approach that we adapted to meet the unique challenges at McArthur River. It involves:

• drilling a series of overlapping holes through the ore zone from a raisebore chamber in waste rock above the mineralization

• collecting the broken ore at the bottom of the raises using line-of-sight remote-controlled scoop trams, and transporting it to a grinding circuit

• once mining is complete, filling each raisebore hole with concrete

• when all the rows of raises in a chamber are complete, removing the equipment and filling the entire chamber with concrete

• starting the process again with the next raisebore chamber

We have used the raisebore mining method to successfully extract about 230 million pounds (100% basis) since we began mining in 1999.

McArthur River currently has six areas with delineated mineral reserves (zones 1 to 4, zone 4 south and zone B) and eight areas with delineated mineral resources. We are currently mining zone 2 and the lower area of zone 4.

Zone 2 has been actively mined since production began. It is divided into four panels (panels 1, 2, 3 and 5) based on the configuration of the freeze wall around the ore. As the freeze wall is expanded, the inner connecting freeze walls are decommissioned in order to recover the uranium that was inaccessible around the active freeze pipes. Panel 5 represents the upper portion of zone 2, overlying part of the other panels. Mining is nearing completion in panels 1, 2 and 3, and the majority of the remaining zone 2 proven mineral reserves are in panel 5.

Zone 4 is divided into three mining areas: central, north and south. We are actively mining the central area. A new mining area is also under development – zone 4 north – and is forecasted to be in production in 2014.

MANAGEMENT’S DISCUSSION AND ANALYSIS 67

Raisebore mining is scheduled to remain the primary extraction method over the life of mine. We are testing two other mining methods, blasthole stoping and boxhole boring. Upon successful completion of the test programs in 2013, an application will be made to the CNSC to approve these mining methods as secondary extraction methods for McArthur River.

Boxhole boring

Boxhole boring is similar to the raisebore method, but the drilling machine is located below the mineralization, so development is not required above the mineralization. This method is currently being used at a few mines around the world, but had not been used for uranium mining prior to testing at McArthur River.

We expect boxhole boring will only be used as a secondary method, in areas where we determine raiseboring is not feasible or practical. Test mining to date has identified this as a viable mining option; however, only a minor amount of ore is scheduled to be extracted using this method.

Blasthole stoping

Blasthole stoping involves establishing drill access above the mineralization and extraction access below the mineralization. The area between the upper and lower access levels (the stope) is then drilled off and blasted. The broken rock is collected on the lower level and removed by line-of-sight remote-controlled scoop trams, then transported to a grinding circuit. Once a stope is mined out, it is backfilled with concrete to maintain ground stability and allow the next stope in sequence to be mined. This mining method has been used extensively in the mining industry, including uranium mining.

Blasthole stoping is planned in areas where blast holes can be accurately drilled and small stable stopes excavated without jeopardizing the freezewall integrity. We expect this method to complement the raiseboring method and to allow for more economic recovery of ore on the periphery of the orebody, as well as smaller, lower grade areas.

2012 UPDATE

Production

Our share of production in 2012 was 1% higher than our forecast for the year and 2% lower than total production in 2011.

At McArthur River and Key Lake we realized benefits under the production flexibility amendments to the McArthur River and Key Lake operating licences (see Production flexibility) for the fourth consecutive year. Ongoing efforts to improve the efficiency and reliability of the Key Lake mill resulted in record mill performance.

We have mitigated the risk to production in 2013 associated with the transition to the upper mining area of zone 4. We have made productivity improvements on cycle times, which include the use of blasthole stoping in smaller, lower-grade areas of the mine located away from the freezewalls. In addition, we have changed the sequencing of the raises in zone 2, panel 5, which will improve productivity.

New mining areas

We continued drilling to install the freezewall in the upper mining area of zone 4 north. We expect to finish installing brine circulation lines and start freezing upper zone 4 north in 2013, and begin production from this area in 2014.

In addition to the underground work, we have started to upgrade our electrical infrastructure on surface to address the future need for increased ventilation and freeze capacity associated with mining new zones and increasing mine production.

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McArthur River production expansion

In 2012, we completed the feasibility study on the McArthur River extension project, and based on the positive results, revised our mine plan to incorporate a mine expansion. This includes an increase in our annual production rate to 22 million pounds U₃O₈ (100% basis) by 2018, subject to receipt of regulatory approval.

We were notified by the CNSC that the environmental assessment for the planned increase in production would be transitioned to the CNSC licensing and compliance processes rather than the federal environmental assessment process. We are developing plans to complete this regulatory process.

In addition, we must continue to successfully transition into new mine areas through mine development and investment in support infrastructure. As part of this multi-year project, we plan to:

• expand the freeze plant and electrical distribution systems

• increase ventilation by sinking a fourth shaft at the northern end of the mine

• improve our dewatering system and expand our water treatment capacity.

McArthur River technical report

In 2012, we updated the McArthur River technical report. Highlights included:

• a 19% increase in our share of the mineral reserves due to a 22% addition in tonnage and a slight decrease in the estimated average grade. For more information, see Mineral reserves and resources on page 98.

• 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

• 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

Key Lake extension project and mill revitalization

The Key Lake mill began operating in 1983. Mill production at Key Lake is expected to closely follow McArthur River production, subject to receipt of regulatory approval. As part of our Key Lake extension environmental assessment, we are seeking approval to increase Key Lake’s nominal annual production rate to 25 million pounds U₃O₈ and to increase our tailings capacity.

The mill revitalization plan includes upgrading circuits with new technology to simplify operations and improve environmental performance. As part of this plan, we replaced the acid, steam and oxygen plants.

Tailings capacity

This year we:

• advanced the environmental assessment for the Key Lake extension project by submitting the draft environmental impact statement to the regulators, receiving their comments and providing responses

• began flattening the slope of the Deilmann tailings management facility pitwalls, relocating about 80% of the sand

Exploration

In 2012, our surface exploration programs drill tested targets north and south of the current mining areas.

PLANNING FOR THE FUTURE

Production

Forecast: 18.7 million pounds of U₃O₈ per year until 2017 (our share will be 13.1 million pounds), with a planned production increase in 2018.

New mining zones

Zone 4 north is the next area to be mined. It is currently under development and we forecast production to begin in 2014. We expect to start freezing the lower mining area of zone 4 north in 2013.

MANAGEMENT’S DISCUSSION AND ANALYSIS 69

We expect to use raisebore mining in this area, applying the ground freezing experience we gained in zone 2, panel 5. This should significantly improve production efficiencies compared to boxhole boring.

In 2013, we also expect to complete the expansion of the existing freeze plant to support our production plans at McArthur River.

Mill revitalization

In 2013, we expect to:

• complete installation and commissioning of a new electrical substation

• complete the structural steel work and equipment installation for a new calciner, to be commissioned in 2014

Tailings capacity

In 2013, we expect to:

• complete flattening of the Deilmann tailings management facility pitwalls and begin constructing a buttress to prevent sand sloughing when the water level is raised

• advance the environmental assessment for the Key Lake extension project, by submitting the final environmental impact statement for review by the provincial and federal regulators and pursue the required regulatory approvals

See Key Lake tailings capacity risk on page 71 for additional information.

Licensing

We will be applying for a renewal of our McArthur River and Key Lake operating licences in 2013. The Canadian Nuclear Safety Commission has scheduled a one-day hearing in the third quarter as part of the application process.

Exploration

In 2013, we plan to continue advancing the underground exploration drifts to the southwest and northeast directions. Additional drilling is planned underground to delineate zone A, and from surface to identify additional mineral resources in the deposit.

MANAGING OUR RISKS

Production at McArthur River/Key Lake poses many challenges: control of groundwater, weak rock formations, radiation protection, water inflow, mine area transitioning, regulatory approvals and tailings capacity. Operational experience gained since the start of production has resulted in a significant reduction in risk.

Water inflow risk

The greatest risk is production interruption from water inflows. A 2003 water inflow resulted in a three-month suspension of production. We also had a small water inflow in 2008 that did not impact production.

The consequences of another water inflow at McArthur River would depend on its magnitude, location and timing, but could include a significant interruption or reduction in production, a material increase in costs or a loss of mineral reserves.

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We take the following steps to reduce the risk of inflows, but there is no guarantee that these will be successful:

• Ground freezing: Before mining, we drill freezeholes and freeze the ground to form an impermeable freezewall around the area being mined. Ground freezing reduces but does not eliminate the risk of water inflows.

• Mine development: We plan for our mine development to take place away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk, and apply extensive additional technical and operating controls for all higher risk development.

• Pumping capacity and treatment limits: Our standard for this project is to secure pumping capacity of at least one and a half times the estimated maximum sustained inflow. We review our dewatering system and requirements at least once a year and before beginning work on any new zone.

We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum sustained inflow.

Transition to new mining areas

In order to successfully achieve the planned production schedule, we must continue to successfully transition into new mining areas, which includes mine development and investment in critical support infrastructure.

The zone 4 north transition planned in late 2014 carries a slightly higher transition risk than other mining area transitions due to the site’s limited flexibility to offset a shortfall in production due to schedule delays.

Labour relations

The current collective agreement with unionized employees at the McArthur River and Key Lake operations expires on December 31, 2013. There is risk to production in 2014 if we are unable to reach an agreement and employees go on strike.

Key Lake tailings capacity risk

Tailings from processing McArthur River ore are deposited in the Deilmann tailings management facility. At current production rates, the facility will reach licensed capacity by 2018. A significant delay in obtaining or a failure to receive, the necessary regulatory approval for the expansion of the facility could interrupt or prevent the operation of McArthur River and Key Lake as planned.

In the past, sloughing of material from the pitwalls has resulted in loss of capacity. Technical studies show that stabilizing and reducing water levels in the pit enhances the stability of the pitwalls and reduces the risk of sloughing. In 2009, regulators approved our plan for the long-term stabilization of the Deilmann tailings management facility pitwalls. We are implementing the plan, and expect it will be complete in 2014. We are proceeding with the environmental assessment to support an application for regulatory approval to deposit tailings to a much higher level. This would provide enough tailings capacity to mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

We also manage the risks listed on pages 62 to 63.

MANAGEMENT’S DISCUSSION AND ANALYSIS 71

Uranium – operating properties

	Rabbit Lake The Rabbit Lake operation, which opened in 1975, is the longest operating uranium production facility in North America, and the second largest uranium mill in the world.
Location	Saskatchewan, Canada
Ownership	100%
End product	Uranium concentrates
ISO certification	ISO 14001 certified
Mine type	Underground
Estimated reserves	22.8 million pounds (proven and probable), average grade U3O8 : 0.70%
Estimated resources	6.4 million pounds (indicated), average grade U3O8 : 0.60% 10.3 million pounds (inferred), average grade U3O8: 1.24%
Mining methods	Vertical blasthole stoping
Licenced capacity	Mill: maximum 16.9 million pounds per year; currently 11 million
Total production: 1975 to 2012	186.3 million pounds
2012 production	3.8 million pounds
2013 forecast production	4.2 million pounds
Estimated decommissioning cost	$105 million (2008 estimate – currently under review)

2012 UPDATE

Production

Production this year was about 3% higher than our forecast for the year and similar to 2011 production.

Development and production continued at Eagle Point mine. At the mill we were able to achieve improved performance by replacing key pieces of mill infrastructure and improving the efficiency of the mill operation schedule.

In 2011, we received regulatory approval to begin exploration–related development and drilling on a new ore zone located about 650 metres northeast of the existing mine workings. In 2012, we completed a portion of the development work and in 2013, plan to complete the development and continue drilling to further evaluate this zone.

Exploration

We continued our underground drilling reserve replacement program.

Exploration work was completed directly to the east and northeast of the current mine workings and returned promising results.

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PLANNING FOR THE FUTURE

Production

We expect to produce 4.2 million pounds in 2013.

Tailings capacity

We continued to enhance our milling processes and as a result of improved settling of solid material in the tailings management facility, we expect to have sufficient tailings capacity to support milling of Eagle Point ore until about the end of 2017 (based upon expected ore grades and milling rates).

We are planning to expand the existing tailings management facility by the end of 2017 to support the extension of Rabbit Lake’s mine life and provide additional tailings capacity to process ore from other potential sources. We need an environmental assessment and regulatory approval to proceed with any increase in capacity.

Exploration

We will continue our underground drilling reserve replacement program in 2013. We plan to continue surface drilling in areas of interest east and northeast of the mine.

Reclamation

As part of our multi-year site-wide reclamation plan, we spent over $7.5 million in 2012 to reclaim facilities that are no longer in use and plan to spend over $2.7 million in 2013.

MANAGING OUR RISKS

We manage the risks listed on pages 62 and 63.

MANAGEMENT’S DISCUSSION AND ANALYSIS 73

Uranium – operating properties

	Smith Ranch-Highland We operate Smith Ranch and Highland as a combined operation. Each has its own processing facility, but the Smith Ranch central plant currently processes all the uranium and the Highland plant is currently idle. Together, they form the largest uranium production facility in the United States. In 2013 we expect to start production from the North Butte satellite operation with final uranium processing also at the Smith Ranch-Highland processing facilities.
Location	Wyoming, US
Ownership	100%
End product	Uranium concentrates
ISO certification	ISO 14001 certified
Estimated reserves	Smith Ranch-Highland: 6.3 million pounds (proven and probable), average grade U3O8 : 0.09% North Butte-Brown Ranch: 3.3 million pounds (proven and probable), average grade U3O8 : 0.08%
Estimated resources	Smith Ranch-Highland: 23.0 million pounds (measured and indicated), average grade U3O8 : 0.06% 6.6 million pounds (inferred), average grade U3O8: 0.05% North Butte-Brown Ranch 12.3 million pounds (measured and indicated), average grade U3O8 : 0.08% 0.8 million pounds (inferred), average grade U3O8: 0.06%
Mining methods	In situ recovery (ISR)
Licenced capacity	Wellfields: 3 million pounds per year including North Butte Processing plants: 5 million pounds per year including Highland mill
Total production: 2002 to 2012	15.9 million pounds
2012 production	1.1 million pounds
2013 forecast production	1.8 million pounds
Estimated decommissioning cost	$182 million (US) (including North Butte satellite operation)

2012 UPDATE

Production

Production this year was slightly lower than our third quarter guidance and lower than 2011 production. The lengthened review process to obtain regulatory approvals for new mine units (wellfields) at Smith Ranch-Highland continued to impact production this year. One significant new mine unit was in full production by August, following the receipt of all necessary approvals. Approval for a portion of another important mine unit was received at the end of the year, enabling us to bring it into production in early 2013. We continue to seek regulatory approvals to proceed with the rest of our expansion plans.

We have made good progress on construction of the satellite plant and development of the first wellfield at North Butte in Wyoming in line with our growth plans.

Licensing

The regulators continue to review our licence renewal application. We are allowed to continue with all previously approved activities during the licence renewal process.

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PLANNING FOR THE FUTURE

Production

In 2013, we expect to produce 1.9 million pounds, including 0.3 million pounds from our North Butte satellite operation.

We continue to seek regulatory approvals to proceed with expansions at our various satellite operations in Wyoming. The regulators are constrained by a shortage of resources as they try to work through a large volume of permit and licence amendment requests from resource companies. However, we are beginning to receive some approvals. We continue to communicate with them to ensure we understand and meet their information needs in a timely manner.

New Mining Areas

We will continue construction of the satellite plant and the first wellfields at North Butte. Once commissioned, we expect to produce approximately 300,000 pounds in 2013 and ramp up to a target annual production rate of more than 700,000 pounds per year by 2015.

Exploration

We are continuing our exploration activity with the objective of extending the mine life at Smith Ranch-Highland and satellite properties.

MANAGING OUR RISKS

The operating environment is becoming more complex as public interest and regulatory oversight increase. This may affect our plans to increase production. We also manage the risks listed on pages 62 and 63.

MANAGEMENT’S DISCUSSION AND ANALYSIS 75

Uranium – operating properties

	Crow Butte Crow Butte was discovered in 1980 and began production in 1991. It is the first uranium mine in Nebraska, and is a significant contributor to the economy of northwest Nebraska.
Location	Nebraska, US
Ownership	100%
End product	Uranium concentrates
ISO certification	ISO 14001 certified
Estimated reserves	3.0 million pounds (proven), average grade U3O8: 0.12%
Estimated resources	12.2 million pounds (indicated), average grade U3O8 : 0.21% 5.4 million pounds (inferred), average grade U3O8: 0.12%
Mining methods	In situ recovery (ISR)
Licenced capacity (processing plants and wellfields)	1 million pounds per year
Total production: 2002 to 2012	8.3 million pounds
2012 production	0.8 million pounds
2013 forecast production	0.7 million pounds
Estimated decommissioning cost	$40 million (US)

2012 UPDATE

Production

Production this year was slightly higher than our forecast and similar to 2011 production.

Licensing

The regulators continued to review our applications to expand and re-license Crow Butte. We are allowed to continue with all previously approved activities during the licence renewal process.

PLANNING FOR THE FUTURE

Production

In 2013, we expect to produce 0.7 million pounds.

We continue to seek regulatory approvals to proceed with expansions at our various satellite operations in Nebraska. The regulators are constrained by a shortage of resources as they try to work through a large volume of permit and licence amendment requests from resource companies; however, we are beginning to receive some approvals. We continue to communicate with them to ensure we understand and meet their information needs in a timely manner.

Managing our risks

The operating environment is becoming more complex as public interest and regulatory oversight increase. This may affect our plans to increase production. We also manage the risks listed on pages 62 and 63.

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Uranium – operating properties

	Inkai Inkai is a very significant uranium deposit, located in Kazakhstan. There are two production areas (blocks 1 and 2) and an exploration area (block 3). The operator is joint venture Inkai limited liability partnership, which we jointly own (60%) with Kazatomprom (40%). Inkai is one of our three material uranium properties.
Location	South Kazakhstan
Ownership	60%
End product	Uranium concentrates
Certifications	BSI OHSAS 18001 ISO 14001 certified
Estimated reserves (our share)	53.9 million pounds (proven and probable), average grade U3O8 : 0.07%
Estimated resources (our share)	28.0 million pounds (indicated), average grade U3O8 : 0.08% 146.6 million pounds (inferred), average grade U3O8: 0.05%
Mining methods	In situ recovery (ISR)
Licenced capacity (wellfields)	approved: 3.9 million pounds per year, (our share 2.3 million pounds per year) application: 5.2 million pounds per year, (our share 3.0 million pounds per year – see Licensing)
Total production: 2008 to 2012 (our share)	9.0 million pounds
2012 production (our share)	2.6 million pounds
2013 forecast production (100% basis)	5.2 million pounds (our share of production 3.0 million pounds – see Licensing)
Estimated decommissioning cost (100% basis )	$14 million (US)

2012 UPDATE

Production

Production this year was 4% higher than our forecast for the year and 4% higher than production in 2011.

We continued to bring on additional wellfields to maintain some new, typically higher grade, wellfields in the production mix. The processing plant has the capacity to produce at an annual rate of 5.2 million pounds (100% basis) depending on the grade of the production solution. Production at Inkai steadily improved over the course of the year and the facility is now operating at design capacity. However, regulatory approval is required to carry out production at the annual rate of 5.2 million pounds (100% basis).

Licensing

An amendment to Inkai’s resource use contract was signed early in 2011, and Inkai received government approval to:

• increase annual production from blocks 1 and 2 to 3.9 million pounds (100% basis)

• carry out a five-year assessment program at block 3 that includes delineation drilling, uranium resource estimation, construction and operation of a test leach facility, and completion of a feasibility study

MANAGEMENT’S DISCUSSION AND ANALYSIS 77

In 2011, we also signed an MOA (2011 MOA) with our partner, Kazatomprom, to increase production from blocks 1 and 2 to 5.2 million pounds (100% basis). Under the 2011 MOA, our share of Inkai’s annual production will be 2.9 million pounds with the processing plant at full capacity. We will also be entitled to receive profits on 3.0 million pounds.

To implement the increase, we continue to await government approval of an amendment to the resource use contract.

Project funding

We have a loan agreement with Inkai whereby we funded Inkai’s project development costs. As of December 31, 2012, there was $133 million (US) of principal outstanding on the loan. In 2012, Inkai paid $4.3 million (US) in interest on the loan and repaid $59 million (US) of principal.

Under the loan agreement, Inkai first uses cash available every year to pay accrued interest. Inkai then uses 80% of the remaining cash available for distribution to repay principal outstanding on the loan. The remaining 20% is distributed as dividends to the owners.

We have also agreed to advance funds for Inkai’s work on block 3 until the feasibility study is complete. As of December 31, 2012 the block 3 loan principal amounted to $85 million (US).

Uranium conversion project and doubling production

In 2012, we entered into 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 (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, which sought to align the annual production increase with the development of uranium conversion capacity. Kazatomprom’s primary focus is now 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

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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.

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

• 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

Block 3 exploration

In April 2012, Inkai received regulatory approval for the detailed block 3 delineation and test leach work programs. Inkai continued delineation drilling, started technological drilling of test wellfields, continued with infrastructure development and started construction of a test leach facility for the block 3 assessment program.

Based on earlier agreements, profits from future block 3 production are to be shared on a 50:50 basis with our partner, instead of based on our ownership interests.

PLANNING FOR THE FUTURE

Production

We expect our share of production to be 3.0 million pounds in 2013 from blocks 1 and 2.

Block 3 exploration

In 2013, Inkai expects to:

• complete delineation drilling

• complete construction of the test leach facility and test wellfields

• extend power line to block 3 facilities

• start operation of the test wellfields

MANAGING OUR RISKS

Regulatory approvals

Our 2013 and future annual production targets for Inkai assume, and we expect, that 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.

There is no certainty Inkai will receive these permits or approvals. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2013 and future annual production targets and we may have to re-categorize some of Inkai’s mineral reserves as resources.

Supply of sulphuric acid

There were no interruptions to sulphuric acid supply during 2012. Given the importance of sulphuric acid to Inkai’s mining operations and shortages in previous years, we continue to closely monitor its availability. Our production may be less than forecast if there is a shortage.

Political risk

Kazakhstan declared itself independent in 1991 after the dissolution of the Soviet Union. Our Inkai investment, and our plans to increase production, are subject to the risks associated with doing business in developing countries, which have significant potential for social, economic, political, legal, and fiscal instability. Kazakh laws and regulations are complex and still developing and their application can be difficult to predict. To maintain and increase Inkai production, we need ongoing support, agreement and co-operation from our partner and the government.

MANAGEMENT’S DISCUSSION AND ANALYSIS 79

The principal legislation governing subsoil exploration and mining activity in Kazakhstan is the Subsoil Use Law dated June 24, 2010. It replaces the Law on the Subsoil and Subsoil Use, dated January 27, 1996.

In general, Inkai’s licences are governed by the version of the subsoil law that was in effect when the licences were issued in April 1999, and new legislation applies to Inkai only if it does not worsen Inkai’s position. Changes to legislation related to national security, among other criteria, however, are exempt from the stabilization clause in the resource use contract. The Kazakh government interprets the national security exemption broadly.

With the new subsoil law, the government continues to weaken its stabilization guarantee. The government is broadly applying the national security exception to encompass security over strategic national resources.

The resource use contract contains significantly broader stabilization provisions than the new subsoil law, and these contract provisions currently apply to us.

To date, the new subsoil law has not had a significant impact on Inkai. We continue to assess the impact. See our annual information form for an overview of this change in law.

We also manage the risks listed on pages 62 and 63.

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Uranium – development project

	Cigar Lake Cigar Lake is the world’s second largest high-grade uranium deposit, with grades that are 100 times the world average. We are a 50% owner and the mine operator. Cigar Lake, which is being developed and scheduled to begin production this year, is one of our three material uranium properties.
Location	Saskatchewan, Canada
Ownership	50.025%
End product	Uranium concentrates
Mine type	Underground
Estimated reserves (our share)	108.4 million pounds (proven and probable), average grade U3O8 : 18.30%
Estimated resources (our share)	1.1 million pounds (measured and indicated), average grade U3O8 : 2.27% 49.5 million pounds (inferred), average grade U3O8: 12.01%
Mining methods	Jet boring
Target production date	Begin commissioning in ore mid-2013 First packaged pounds in the fourth quarter of 2013
Target annual production (our share)	9 million pounds at full production
2013 forecast production (our share)	0.3 million pounds
Estimated decommissioning cost (100% basis )	$49 million (pending regulatory review)

MANAGEMENT’S DISCUSSION AND ANALYSIS 81

BACKGROUND

Development

We began developing the Cigar Lake underground mine in 2005, but development was delayed due to water inflows (two in 2006 and one in 2008). The first inflow flooded shaft 2 while it was under construction. The second inflow flooded the underground development and we began remediation late in 2006. In 2008, another inflow interrupted the dewatering of the underground development. We sealed the inflows and completed dewatering of shafts 1 and 2. In 2011, we completed remediation of the underground.

Mining method

We will use a number of innovative methods and techniques to mine the Cigar Lake deposit:

Bulk freezing

The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. We will freeze the ore zone and surrounding ground in the area to be mined to prevent water from entering the mine and to help stabilize weak rock formations.

Our plan is to use a hybrid freezing approach. We will use surface freezing to support the rampup period and underground freezing for the longer term development of the mine. Through 2012, we continued to drill freezeholes from surface, expand the surface freezing infrastructure and put the new freezeholes in operation. To meet our production schedule, the ground has to be fully frozen in the area being mined before we begin jet boring.

Jet boring

After many years of test mining, we selected jet boring, a non-entry mining method, which we have developed and adapted specifically for this deposit. Overall, our initial test program was a success and met all initial objectives. This method involves:

• drilling a pilot hole into the frozen orebody, inserting a high pressure water jet and cutting a cavity out of the frozen ore

• collecting the ore and water mixture (slurry) from the cavity and pumping it to storage (sump storage) allowing it to settle

• using a clamshell, transporting the ore from the sump storage to a grinding and processing circuit, eventually loading a tanker truck with ore slurry for transport to the mill

• once mining is complete, filling each cavity in the orebody with concrete

• starting the process again with the next cavity

Jet boring system process

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We have divided the orebody into production panels, and will have one jet boring mining unit operating in a panel. At least four production panels need to be frozen at one time to achieve the full production rate of 18 million pounds per year. At full production, two jet boring machines will be working at a time, while the other two are being moved, set up, in the backfill cycle or on maintenance.

Milling

We have signed agreements with the owners of the Cigar Lake project and McClean Lake mill to process all Cigar Lake’s ore slurry at the McClean Lake mill. To process Cigar Lake ore slurry, a number of mill modifications have been completed. The McClean Lake joint venture is required to further modify and expand the mill to process and package all of Cigar Lake’s current mineral reserves. The Cigar Lake joint venture has agreed to pay for the capital costs for such modification and expansion.

2012 UPDATE

During the year, we:

• completed the sinking of shaft 2 to its final depth of 500 metres

• began installing shaft 2 infrastructure, including construction of a concrete ventilation partition, installation of electrical cable, water services, ore slurry pipes and hoist systems

• began commissioning of the surface ore loadout facility

• remediated a portion of an existing mine development tunnel and continue to explore ways to optimize our methods of ground support

• resumed underground development in the north end of the mine

• completed mine development on the 500 metre level

• replaced temporary contingency pumps with permanent infrastructure

• completed the Seru Bay pipeline

• completed all engineering designs and drawings for the project

• constructed the primary clarifier infrastructure

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

• began preliminary commissioning and system testing

• established temporary infrastructure to support testing in waste rock

Costs

As of December 31, 2012, we had:

• invested about $911 million for our share of the construction costs to develop Cigar Lake

• expensed about $86 million in remediation expenses

• expensed about $63 million in standby costs

Our total share of the capital cost for this project is about $1.1 billion since we began development in 2005. In order to bring Cigar Lake into production in 2013, we estimate our share of capital expenditures will be about $182 million, including $27 million on modifications to the McClean Lake mill. Our share of standby charges until production is achieved this year are estimated to be about $52 million.

Licensing

The Canadian Nuclear Safety Commission (CNSC) approved AREVA’s amendment to the operating licence for the McClean Lake mill to process Cigar Lake ore.

MANAGEMENT’S DISCUSSION AND ANALYSIS 83

PLANNING FOR THE FUTURE

Production

In 2013, we expect to:

• test the jet boring unit in waste and begin commissioning of the system

• complete the installation of all infrastructure required to begin production

• bring the mine into production in mid-2013

• produce the first packaged pounds from AREVA’s McClean Lake mill in the fourth quarter

We expect our share of production to be 0.3 million pounds in 2013.

Given the scale of this project and the challenging nature of the geology and mining method, we have made significant progress. We will continue to develop this asset in a safe and deliberate manner to ensure we realize the economic benefits of this project.

Licensing

We have submitted an operating licence application to the CNSC. The CNSC will be holding a public hearing in the second quarter of 2013 as part of the process to obtain our operating licence. Our construction licence is currently set to expire on December 31, 2013. We anticipate that Cigar Lake will be in a position to start mining in ore following the safe commissioning of the ore processing circuits in mid-2013.

Caution regarding forward-looking information

Our expectations and plans regarding Cigar Lake, including our expected share of 2013 production and capital costs, are forward-looking information. They are based on the assumptions and subject to the material risks discussed on pages 3 and 4, and specifically on these assumptions and risks:

Assumptions

• there is no material delay or disruption in our plans as a result of ground movements, cave ins, additional water inflows, a failure of seals or plugs used for previous water inflows, natural phenomena, delay in acquiring critical equipment, equipment failure or other causes

• there are no labour disputes or shortages

• our expectation that the jet boring mining method will be successful and that we will be able to obtain the additional jet boring system units we require on schedule

• we obtain contractors, equipment, operating parts, supplies, regulatory permits and approvals when we need them

• processing plants are available and function as designed and sufficient tailings facility capacity is available

• our mineral reserves estimate and the assumptions it is based on are reliable

• our Cigar Lake development, mining and production plans succeed

Material risks

• an unexpected geological, hydrological or underground condition or an additional water inflow, further delays our progress

• ground movements or cave ins

• we cannot obtain or maintain the necessary regulatory permits or approvals

• natural phenomena, labour disputes, equipment failure, delay in obtaining the required contractors, equipment, operating parts and supplies or other reasons cause a material delay or disruption in our plans

• processing plants are not available or do not function as designed and sufficient tailings facility capacity is not available

• our mineral reserves estimate is not reliable

• our development, mining or production plans for Cigar Lake are delayed or do not succeed for any reason, including technical difficulties with the jet boring mining method or our inability to acquire any of the required jet boring equipment

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MANAGING OUR RISKS

Cigar Lake is a challenging deposit to develop and mine. These challenges include control of groundwater, weak rock formations, radiation protection, water inflow, mining method uncertainty, regulatory approvals, tailings capacity, surface and underground fires and other mining-related challenges. To reduce this risk, we are applying our operational experience and the lessons we have learned about water inflows at McArthur River and Cigar Lake.

Water inflow risk

A significant risk to development and production is from water inflows. The 2006 and 2008 water inflows were significant setbacks.

The consequences of another water inflow at Cigar Lake would depend on its magnitude, location and timing, but could include a significant delay in Cigar Lake’s development or production, a material increase in costs or a loss of mineral reserves.

We take the following steps to reduce the risk of inflows, but there is no guarantee that these will be successful:

• Bulk freezing: Two of the primary challenges in mining the deposit are control of groundwater and ground support. Bulk freezing reduces but does not eliminate the risk of water inflows.

• Mine development: We plan for our mine development to take place away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk, and apply extensive additional technical and operating controls for all higher risk development.

• Pumping capacity and treatment limits: We have pumping capacity to meet our standard for this project of at least one and a half times the estimated maximum inflow.

We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum inflow.

Jet boring mining method and units

We have successfully demonstrated the jet boring mining method in trials. This method, however, has not been proven at full production. We have developed and adapted this method specifically for this deposit. As we ramp up production, there may be some technical challenges, which could affect our production plans. There is a risk the rampup to full production may take longer than planned and that the full production rate may not be achieved on a sustained and consistent basis. A comprehensive testing, pre-commissioning, commissioning and startup plan has been implemented to assure successful startup and on-going operations. We are confident we will be able to solve challenges that may arise, but failure to do so would have a significant impact on our business.

Our mining plan requires four jet boring system units. We currently have one unit and in 2011 agreed to purchase an additional three units. There is a risk that rampup to full production at Cigar Lake may take longer than planned if the manufacture or delivery of these three units does not take place as scheduled. As part of our startup plan noted above, we are working with our supplier to assure timely delivery of these units. The second unit is scheduled to arrive in Canada in early 2013 and work has begun on the third unit at the supplier’s facilities.

We also manage the risks listed on pages 62 and 63.

MANAGEMENT’S DISCUSSION AND ANALYSIS 85

Uranium – projects under evaluation

	Kintyre Kintyre is a uranium deposit that is amenable to open pit mining techniques. We own 70% and are the operator.
Location	Western Australia
Ownership	70%
End product	Uranium concentrates
Mine type	Open pit
Estimated resources (our share)	38.7 million pounds (indicated), average grade U3O8 : 0.58% 6.7 million pounds (inferred), average grade U3O8: 0.46%

BACKGROUND

In August 2008, we paid $346 million (US) to acquire a 70% interest in Kintyre.

2012 UPDATE

This year we:

• carried out further exploration drilling to test for other potential satellite deposits

• completed the prefeasibility study

• prepared a draft Environmental Review and Management Program

• signed the Kintyre Mining Development Indigenous Land Use Agreement with the Martu

Prefeasibility

We completed the prefeasibility study, and found that given the measured and indicated mineral resource estimate of about 55 million pounds (100% basis) at an average grade of 0.58%, current uranium prices and continued cost escalation in Western Australia, the economics of the project are challenging. The study was based on an open pit mine with an estimated mine life of about seven years, estimated total production of about 40 million pounds of packaged uranium at an average production rate of about 6 million pounds per year. To break even, the prefeasibility study indicates the project would require an average realized price of about $67 (US) or greater total production at uranium prices similar to today’s spot price.

Based on our review of the current market environment, we will complete the value engineering study currently in progress 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.

86 CAMECO CORPORATION

Impairment charge

During the fourth quarter of 2012, we recorded a $168 million write-down of the carrying value of our interest in Kintyre. Due to the recent weakening of the uranium market, no increase in mineral resources in 2012 and the decision not to proceed to a feasibility study, we concluded it was appropriate to recognize an impairment charge for this asset. Kintyre remains an important asset in our portfolio. However, given the current state of the market, it was necessary to reduce its carrying value at this time.

Exploration

Ten additional prospective areas on the property were drill tested in 2012 and to date, no additional resources have been identified.

PLANNING FOR THE FUTURE

Kintyre provides a potential opportunity for us to diversify our portfolio in mining method and geography. Any decision to further advance the Kintyre project through our stage gate process will ultimately be based on positive project economics—see Stage gate process on page 18 for additional details.

Our plan for 2013 is to:

• complete the value engineering study

• complete registration of the Kintyre Mining Development Indigenous Land Use Agreement with the relevant government authority

• submit an Environmental Review and Management Program

• carry out further exploration to test for potential satellite deposits at Kintyre and at other regional exploration projects close to Kintyre.

Exploration

In order to fully analyze the existing deposit data and prepare to effectively drill test any remaining targets, we will not undertake any additional delineation drilling at Kintyre in 2013. Exploration will be focused on potential satellite deposit targets.

MANAGING THE RISKS

We manage the risks listed on pages 62 and 63.

MANAGEMENT’S DISCUSSION AND ANALYSIS 87

Uranium – projects under evaluation

	Millennium Millennium is a uranium deposit in northern Saskatchewan that we expect will use our excess milling capacity. We are the operator.
Location	Saskatchewan, Canada
Ownership	69.9%
End product	Uranium concentrates
Mine type	Underground
Estimated resources (our share)	47.7 million pounds (indicated), average grade U3O8 : 4.16% 15.6 million pounds (inferred), average grade U3O8: 5.29%

BACKGROUND

The Millennium deposit was discovered in 2000, and was delineated through geophysical survey and drilling work between 2000 and 2007.

2012 UPDATE

This year we:

• continued work on the environmental assessment

• completed a summer drill program, which increased our indicated and inferred mineral resource estimate

• carried out additional studies and design work to advance the project

In June, we closed an agreement with AREVA Resources Canada Inc. to purchase AREVA’s 27.94% interest in the Millennium project for $150 million. With the closing, our interest in the Millennium project increased to 69.9%. The remaining 30.1% is owned by JCU (Canada) Exploration Co.

The purchase agreement provides AREVA with a 4% royalty on revenue from 27.94% of any production that exceeds 63 million pounds U₃O₈ from the 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.

Highway 905 to 914 connector

In cooperation with several uranium industry partners in Saskatchewan, we have been working with the provincial government on a plan 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 and provide additional options for the milling of Millennium and other regional sources of ore. It will also 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 subject to the decision to develop the Millennium deposit. The industry partners will share the remaining cost.

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PLANNING FOR THE FUTURE

Our plan for 2013 is to:

• submit the final environmental impact statement to regulators

• complete an exploration drill program to test targets near the deposit

• continue to advance the project toward a development decision at a pace aligned with market opportunities, using our stage gate process

MANAGING OUR RISKS

The English River First Nation (ERFN) has selected surface lands covering the Millennium deposit in a claim for Treaty Land Entitlement (TLE). The Saskatchewan government has rejected the selection, but the ERFN has challenged the government’s decision in the courts and this litigation continues. The TLE process does not affect our mineral rights, but it could have an impact on the surface rights and benefits we ultimately negotiate as part of the development of this deposit.

Environment Canada has brought forward a national recovery plan for woodland caribou that has the potential to impact economic and social development in northern Saskatchewan. Additional research work is being conducted so that a determination can be made on the sustainability of the species within the region. The research could result in measures being taken to further limit habitat disturbance in order to improve the health of the woodland caribou population in northern Saskatchewan and it could have an impact on our ability to develop this deposit.

We also manage the risks listed on pages 62 and 63.

MANAGEMENT’S DISCUSSION AND ANALYSIS 89

Uranium – projects under evaluation

	Yeelirrie Yeelirrie is a near-surface calcrete-style deposit that is amenable to open pit mining techniques. It is one of Australia’s largest undeveloped uranium deposits.
Location	Western Australia
Ownership	100%
End product	Uranium concentrates
Mine type	Open pit

BACKGROUND

The Yeelirrie deposit was discovered in 1972 and is one of Australia’s largest undeveloped uranium deposits.

In December 2012, we completed the purchase of Yeelirrie from BHP Billiton Yeelirrie Development Company Pty Ltd for $430 million (US) and then paid $22 million (US) in stamp duty to the government of Western Australia. Yeelirrie represents an attractive deposit that fits well with our long-term strategy.

A historic estimate of the mineral content of Yeelirrie was prepared for BHP Billiton in June 2012 by an international mining consulting firm. The historic estimate indicates that Yeelirrie hosts measured and indicated mineral resources of approximately 139 million pounds of U₃O₈, with an average grade of approximately 0.13% U₃O₈ and inferred resource of approximately 5 million pounds at 0.10% U₃O₈. This historic estimate uses resource categories from the Australasian Code for Reporting of Identified Mineral Resources and Ore Reserves (the JORC Code). The acquisition closed at the end of the year and we have not had sufficient time for a qualified person to classify the historic estimate as current mineral resources for purposes of National Instrument 43-101 – Standards of Disclosure for Mineral Projects (NI 43-101). We are not treating the historic estimate as current mineral resources.

Summary of historic estimate for the Yeelirrie project

(Non-compliant with NI 43-101)

(tonnes in thousands; pounds in millions)

MEASURED RESOURCE						INDICATED RESOURCE						INFERRED RESOURCE
TONNES		GRADE % U3O8		CONTENT (lbs U3O8)		TONNES		GRADE % U3O8		CONTENT (lbs U3O8)		TONNES		GRADE % U3O8		CONTENT (lbs U3O8)
	16.61		0.16		60.3		31.03		0.12		78.9		2.41		0.10		5.3

The above historic estimate was based on 10,250 surface holes, of which nearly 4,000 diamond drill holes had assay values and the rest had uranium grade measured by downhole radiometric probing. The interpretation of the mineralization envelopes at a cut-off of 0.05% U₃O₈ focused less on strict application of a grade cut-off, and more on the assumption of significant continuity of the mineralized zones. The uranium grade was estimated for blocks of 25m by 25m by 0.5m.

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We consider the historic estimate relevant as an indication of the potential of the Yeelirrie property and believe that the total uranium content of the historic estimate may be overstated by approximately 10%. The historic estimate should not be relied upon as a quantification of mineral resources, given that, in our opinion approximately 50 million pounds of U₃O₈ reported as indicated resources would have to be re-categorized because they are not supported by sufficient drilling density and geochemical assays characterizing the uranium grade and other mineral components of the mineralized material.

PLANNING FOR THE FUTURE

In 2013, we expect to:

• conduct a full document review of Yeelirrie

• complete a mineral resource estimate in accordance with NI 43-101

Yeelirrie is an important asset in our portfolio and is part of our plan to sustain our production beyond 2018. Based on our assessment of the deposit and the benefits we expect to derive, we believe we paid a fair price. We will advance the development of this project at a pace aligned with market opportunities, using our stage gate process.

MANAGING OUR RISKS

We manage the risks listed on pages 62 and 63.

MANAGEMENT’S DISCUSSION AND ANALYSIS 91

Uranium – exploration

In 2012, we adjusted our exploration strategy to focus on the most prospective North American and Australian projects in our portfolio. Exploration is key to ensuring our long-term growth, and since 2008 we have continued to make a significant investment in exploring the land that we hold.

2012 UPDATE

Brownfield exploration

Brownfield exploration is uranium exploration near our existing operations, and includes expenses for advanced exploration projects where uranium mineralization is being defined.

This year we spent $10 million on four brownfield exploration projects, and $24 million for resource definition at Kintyre and Cigar Lake.

Regional exploration

We spent about $45 million on regional exploration programs (including support costs). Saskatchewan was the largest region, followed by Australia, northern Canada, Asia and South America.

PLANS FOR 2013

We plan to spend approximately 5% to 10% less on uranium exploration in 2013 as part of our long-term strategy.

Brownfield exploration

We plan to spend approximately $14 million on eight brownfield exploration projects in the Athabasca Basin and Australia. Our expenditures on projects under evaluation are expected to total $24 million, with the largest amount spent on Inkai block 3.

Regional exploration

We plan to spend about $34 million on 32 projects worldwide, the majority of which are at drill target stage. Among the larger expenditures planned are $9 million to test targets near our US operations and on our US satellite properties, $8 million on the Read Lake project which is adjacent to McArthur River in Saskatchewan, and about $6 million on our Northern Territory projects in Australia.

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Fuel services – refining

	Blind River refinery Blind River is the world’s largest commercial uranium refinery, refining uranium concentrates from mines around the world into UO3.
Location	Ontario, Canada
Ownership	100%
End product	UO3
ISO certification	ISO 14001 certified
Licensed capacity	24 million kgU as UO3 per year (subject to the completion of certain equipment upgrades)
Estimated decommissioning cost	$39 million

2012 UPDATE

Production

Our Blind River refinery produced 13.1 million kgU of UO₃ this year, enabling our conversion business to achieve its production targets.

Licensing

In February, the Canadian Nuclear Safety Commission granted a 10-year operating licence for the Blind River refinery. In addition to the new operating licence, the annual licensed production capacity was increased from 18 million kgU as UO₃ to 24 million kgU as UO₃ subject to the completion of certain equipment upgrades.

MANAGING OUR RISKS

We manage the risks listed on pages 62 and 63.

MANAGEMENT’S DISCUSSION AND ANALYSIS 93

Fuel services – conversion and fuel manufacturing

	Port Hope conversion services Port Hope is the only uranium conversion facility in Canada and the only commercial supplier of UO2 for Canadian-made Candu reactors. We control about 25% of world UF6 conversion capacity.
Location	Ontario, Canada
Ownership	100%
End product	UF6, UO2
ISO certification	ISO 14001 certified
Licensed capacity	12.5 million kgU as UF6 per year 2.8 million kgU as UO2 per year
Estimated decommissioning cost	$102 million

Cameco Fuel Manufacturing Inc. (CFM)

CFM produces fuel bundles and reactor components for Candu reactors.

Location	Ontario, Canada
Ownership	100%
End product	Candu fuel bundles and components
ISO certification	ISO 9001 certified, ISO 14001 certified
Licensed capacity	1.2 million kgU as UO2 as finished bundles
Estimated decommissioning cost	$20 million

Springfields Fuels Ltd. (SFL)

SFL is the newest conversion facility in the world. We contract almost all of its capacity through a toll-processing agreement to 2016.

Location	Lancashire, UK
Toll-processing agreement	Annual conversion of 5 million kgU as UO3 to UF6
Licensed capacity	6.0 million kgU as UF6 per year

2012 UPDATE

Production

Fuel services produced 14.2 million kgU, slightly higher than our plan at the beginning of the year and 3% lower than 2011.

Licensing

In February, the Canadian Nuclear Safety Commission approved a five-year operating licence for the Port Hope conversion facility and a ten-year licence for CFM.

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Labour relations

In July, unionized employees at our fuel manufacturing operations in Port Hope and Cobourg, Ontario voted to accept a new three-year collective agreement. The agreement includes a 5.25% wage increase over the term of the agreement.

Port Hope conversion facility cleanup and modernization (Vision in Motion, formerly Vision 2010)

In December, we received a positive decision from Canada’s Environment Minister to allow us to proceed with the licence amendment from the Canadian Nuclear Safety Commission, an amendment that is required to advance the project.

Springfields toll milling agreement

Based on the current market for UF₆ conversion, we do not anticipate an extension of our toll conversion contract with SFL beyond 2016. We remain fully committed to the current contract. If market conditions improve over the next few years, we would consider resuming our discussions to extend the contract.

PLANNING FOR THE FUTURE

Production

We have increased our production target for 2013 to between 15 million and 16 million kgU.

Port Hope conversion facility cleanup and modernization (Vision in Motion)

In 2013, we expect to commence the licence amendment process required for the project.

MANAGING OUR RISKS

Labour relations

The current collective agreements with unionized employees at the Port Hope Conversion facility will expire on June 30, 2013. Bargaining will begin in April 2013. There is risk to production if we are unable to reach an agreement and employees go on strike.

We also manage the risks listed on pages 62 and 63.

MANAGEMENT’S DISCUSSION AND ANALYSIS 95

NUKEM Gmbh

NUKEM Gmbh is one of the world’s key traders of uranium and uranium-related products.

Offices	Alzenau, Germany (Headquarters, NUKEM Gmbh) Connecticut, US (subsidiary, NUKEM Inc.)
Ownership	100%
Activity	trading of uranium and uranium-related products
2013 forecast sales	9 to 11 million lbs U3O8 and about 500,000 SWU

BACKGROUND

In January 2013, we completed the acquisition of NUKEM. On closing, we paid €107 million ($140 million (US)) to Advent International and other shareholders and assumed its net debt of about €84 million ($111 million (US)).

Under the earn-out provisions in the agreement, we expect to pay Advent a share of NUKEM’s 2012 earnings. An additional payment may be required in 2015 depending on results achieved in 2013 and 2014.

NUKEM’s business model

NUKEM’s purchase contracts are with longstanding supply partners and its sales contracts are with blue-chip utilities which have strong credit ratings.

PLANNING FOR THE FUTURE

In 2013, we expect NUKEM to deliver approximately 9 to 11 million pounds of uranium and about 500,000 SWU.

MANAGING OUR RISKS

NUKEM manages the risks associated with trading and brokering nuclear fuels and services. It participates in the uranium spot market making purchases to place material in higher price contracts. There are risks associated with these spot market purchases including the risk of losses. NUKEM is also subject to counterparty risk of suppliers not meeting their delivery commitments and purchasers not paying for the product delivered. If a counterparty defaults on a payment or other obligation or becomes insolvent, this could significantly affect NUKEM’s contribution to our earnings, cash flows, financial condition or results of operations.

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Electricity

	Bruce Power Limited Partnership (BPLP) BPLP leases and operates four Candu nuclear reactors that have the capacity to provide about 15% of Ontario’s electricity.
Location	Ontario, Canada
Ownership	31.6%
ISO certification	ISO 14001 certified
Expected reactor life	2018 to 2021
Term of lease	2018 – right to extend for up to 25 years
Generation capacity	3,260 MW

BACKGROUND

We are the fuel procurement manager for BPLP’s four nuclear reactors and for Bruce A Limited Partnership’s (BALP) four reactors.

We provide 100% of BPLP’s uranium concentrates and have agreed to supply BALP with the majority of its future uranium concentrates. We also provide 100% of BPLP and BALP’s fuel manufacturing and UO₂ conversion requirements.

2012 UPDATE

Output

BPLP’s produced 26.8 terawatt hours of clean electricity in 2012, 8% higher than in 2011. The capacity factor was 94% compared to 87% in 2011.

PLANNING FOR THE FUTURE

Output

We expect the capacity factor to be 88% in 2013 and actual output to be about 5% to 10% lower than 2012.

MANAGING OUR RISKS

BPLP manages the unique risks associated with operating Candu reactors. The amount of electricity generated, and the cost of that generation, could vary materially from forecast if planned outages are significantly longer than planned, or there are many unplanned outages, either for maintenance, regulatory requirements, equipment malfunction or due to other causes.

BPLP also manages the risks listed on pages 62 and 63.

MANAGEMENT’S DISCUSSION AND ANALYSIS 97

Mineral reserves and resources

Our mineral reserves and resources are the foundation of our company and fundamental to our success.

We have interests in a number of uranium properties. The tables in this section show our estimates of the proven and probable reserves, measured and indicated resources and inferred resources at those properties. However, only three of the properties listed in those tables are material uranium properties for us: McArthur River and Inkai, which are being mined, and Cigar Lake, which is being developed.

We estimate and disclose mineral reserves and resources in five categories, using the definitions adopted by the Canadian Institute of Mining, Metallurgy and Petroleum, and in accordance with Canadian National Instrument 43-101 – Standards of Disclosure for Mineral Projects (NI 43-101), developed by the Canadian Securities Administrators. You can find out more about these categories at www.cim.org.

About mineral resources

Mineral resources do not have demonstrated economic viability, but have reasonable prospects for economic extraction. They fall into three categories: measured, indicated and inferred. Our reported mineral resources are exclusive of mineral reserves.

• Measured and indicated mineral resources can be estimated with a level of confidence sufficient to allow the appropriate application of technical and economic parameters to support evaluation of the economic viability of the deposit.

• measured resources: we can confirm geological and grade continuity to support production planning.

• indicated resources: we can reasonably assume geological and grade continuity to support mine planning.

• inferred mineral resources are estimated using limited information. We do not have enough confidence to evaluate their economic viability in a meaningful way. You should not assume that all or any part of an inferred mineral resource will be upgraded to an indicated or measured mineral resource as a result of continued exploration.

Our share of uranium in the mineral resource tables below is based on our respective ownership interests, except for Inkai which is based on our interest in potential production (57.5%), which differs from our ownership interest (60%). Mineral resources that are not mineral reserves have no demonstrated economic viability.

About mineral reserves

Mineral reserves are the economically mineable part of measured and indicated mineral resources demonstrated by at least a preliminary feasibility study. They fall into two categories:

• proven reserves: the economically mineable part of a measured resource for which a preliminary feasibility study demonstrates that economic extraction is justified

• probable reserves: the economically mineable part of a measured and/or indicated resource for which a preliminary feasibility study demonstrates that economic extraction is justified

We use current geological models, an average uranium price of $61 (US) per pound U₃O₈, and current or projected operating costs and mine plans to estimate our mineral reserves, allowing for dilution and mining losses. We apply our standard data verification process for every estimate.

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.

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We report mineral reserves as the quantity of contained ore supporting our mining plans, and include an estimate of the metallurgical recovery for each uranium property. The estimate of the amount of valuable product that can be physically recovered by the metallurgical extraction process is obtained by multiplying the quantity of contained metal by the planned metallurgical recovery percentage. Our share of uranium in the mineral reserves table below is before accounting for estimated metallurgical recovery and is based on our respective ownership interests, except for Inkai which is based on our interest in planned production (57.5%) assuming an annual production rate of 5.2 million pounds, which differs from our ownership interest (60%).

Changes this year

Our share of proven and probable mineral reserves went from 435 million pounds U₃O₈ at the end of 2011 to 465 million pounds at the end of 2012. The change in reserves was mostly the result of:

• the mining and milling activities, which removed 22.9 million pounds from our mineral inventory

• the conversion of mineral resources to probable mineral reserves from an updated resource model and mine plan at McArthur River

• our decision to report our Inkai mineral reserves based on our interest in planned production (57.5%) rather than as previously reported based on our ownership interest (60%), which resulted in a decrease in our share of mineral reserves of 2.7 million pounds. This is in addition to the decrease due to the 2012 production.

• the addition to mineral reserves at Smith Ranch-Highland from production drilling and production results.

Measured and indicated mineral resources decreased from 254 million pounds U₃O₈ at the end of 2011 to 244 million pounds at the end of 2012. Our share of inferred mineral resources was 287 million pounds U₃O₈.

The variance in resources was mostly the result of:

• the conversion of mineral resources to probable mineral reserves at McArthur River

• a share ownership increase and additional surface drilling results at Millennium

• a decrease of inferred mineral resources at Cigar Lake Phase 2 from additional surface drilling indicating a narrower width of the mineralization

• our decision to report our Inkai mineral resources based on our interest in potential production (57.5%) rather than as previously reported based on our ownership interest (60%), which resulted in a decrease in our share of mineral resources of 7.3 million pounds

• an updated mineral resource estimate following additional surface drilling at the Phoenix deposit

• the underground drilling results at Rabbit Lake.

Qualified persons

The technical and scientific information discussed in this MD&A, including mineral reserve and resource estimates, for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) were approved by the following individuals who are qualified persons for the purposes of NI 43-101:

MCARTHUR RIVER/KEY LAKE

• Alain G. Mainville, director, mineral resources management, Cameco

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

• Greg Murdock, technical superintendent, McArthur River, Cameco

• Les Yesnik, general manager, Key Lake, Cameco

CIGAR LAKE

• Alain G. Mainville, director, mineral resources management, Cameco

• Eric Paulsen, chief metallurgist, technology & innovation, Cameco

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

• Scott Bishop, principal mine engineer, technology & innovation, Cameco

MANAGEMENT’S DISCUSSION AND ANALYSIS 99

INKAI

• Alain G. Mainville, director, mineral resources management, Cameco

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

• Lawrence Reimann, manager, technical services, Cameco Resources

Important information about mineral reserve and resource estimates

Although we have carefully prepared and verified the mineral reserve and resource figures in this document, the figures are estimates, based in part on forward-looking information.

Estimates are based on our knowledge, mining experience, analysis of drilling results, the quality of available data and management’s best judgment. They are, however, imprecise by nature, may change over time, and include many variables and assumptions, including:

• geological interpretation

• extraction plans

• commodity prices and currency exchange rates

• recovery rates

• operating and capital costs

There is no assurance that the indicated levels of uranium will be produced, and we may have to re-estimate our mineral reserves based on actual production experience. Changes in the price of uranium, production costs or recovery rates could make it unprofitable for us to operate or develop a particular site or sites for a period of time. See page 2 for information about forward-looking information.

Please see our mineral reserves and resources section of our annual information form for the specific assumptions, parameters and methods used for McArthur River, Inkai and Cigar Lake mineral reserve and resource estimates.

Important information for US investors

While the terms measured, indicated and inferred mineral resources are recognized and required by Canadian securities regulatory authorities, the US Securities and Exchange Commission (SEC) does not recognize them. Under US standards, mineralization may not be classified as a ‘reserve’ unless it has been determined at the time of reporting that the mineralization could be economically and legally produced or extracted. US investors should not assume that:

• any or all of a measured or indicated mineral resource will ever be converted into proven or probable mineral reserves

• any or all of an inferred mineral resource exists or is economically or legally mineable, or will ever be upgraded to a higher category. Under Canadian securities regulations, estimates of inferred resources may not form the basis of feasibility or prefeasibility studies. Inferred resources have a great amount of uncertainty as to their existence and economic and legal feasibility.

The requirements of Canadian securities regulators for identification of ‘reserves’ are also not the same as those of the SEC, and mineral reserves reported by us in accordance with Canadian requirements may not qualify as reserves under SEC standards.

Other information concerning descriptions of mineralization, mineral reserves and resources may not be comparable to information made public by companies that comply with the SEC’s reporting and disclosure requirements for US domestic mining companies, including Industry Guide 7.

100 CAMECO CORPORATION

Mineral reserves

As at December 31, 2012 (100% basis – only the second last column shows our share)

Proven and probable

(tonnes in thousands; pounds in millions)

		PROVEN						PROBABLE						TOTAL MINERAL RESERVES
PROPERTY	MINING METHOD	TONNES		GRADE % U3O8		CONTENT (lbs U3O8)		TONNES		GRADE % U3O8		CONTENT (lbs U3O8)		TONNES		GRADE % U3O8		CONTENT (lbs U3O8)		CAMECO’S SHARE OF CONTENT (lbs U3O8)		METALLUR- GICAL RECOVERY (%)
McArthur River	underground		365.8		24.18		195.0		684.8		12.18		183.9		1,050.6		16.36		378.9		264.5		98.7
Cigar Lake	underground		233.6		22.31		114.9		303.5		15.22		101.8		537.1		18.30		216.7		108.4		98.5
Rabbit Lake	underground		87.2		0.62		1.2		1,380.7		0.71		21.6		1,467.9		0.70		22.8		22.8		96.7
Key Lake	open pit		61.9		0.52		0.7								61.9		0.52		0.7		0.6		98.7
Inkai	ISR		2,774.3		0.08		5.1		61,031.1		0.07		88.7		63,805.4		0.07		93.8		53.9		85.0
Gas Hills-Peach	ISR								999.2		0.11		2.4		999.2		0.11		2.4		2.4		72.0
North Butte-Brown Ranch	ISR								1,839.3		0.08		3.3		1,839.3		0.08		3.3		3.3		80.0
Smith Ranch-Highland	ISR		1,373.2		0.10		3.0		1,781.5		0.08		3.2		3,154.7		0.09		6.2		6.2		80.0
Crow Butte	ISR		1,117.6		0.12		2.9		17.3		0.18		0.1		1,134.9		0.12		3.0		3.0		85.0
Total			6,013.6		—		322.8		68,037.4		—		405.0		74,051.0		—		727.8		465.1

Notes

Estimates in the above table:

• use an average uranium price of $61 (US)/lb U₃O₈

• are based on an average exchange rate of $1 US=$1.00 Cdn, except Cigar Lake, which is based on an average exchange rate of $1.00 US=$1.10 Cdn

Totals may not add up due to rounding.

Except for the possible Inkai permitting issue referred to below, we do not expect these mineral reserve estimates to be materially affected by metallurgical, environmental, permitting, legal, taxation, socio-economic, political, marketing or other relevant issues.

METALLURGICAL RECOVERY

We report mineral reserves as the quantity of contained ore supporting our mining plans, and include an estimate of the metallurgical recovery for each uranium property. The estimate of the amount of valuable product that can be physically recovered by the metallurgical extraction process is obtained by multiplying quantity of contained metal (content) by the planned metallurgical recovery percentage. Our share of uranium in the table above is before accounting for estimated metallurgical recovery.

ESTIMATES FOR INKAI

Our 2013 and future annual production targets for Inkai assume, and we expect, that 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

There is no certainty Inkai will receive these permits or approvals. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2013 and future annual production targets and we may have to re-categorize some of Inkai’s mineral reserves as resources.

MANAGEMENT’S DISCUSSION AND ANALYSIS 101

Mineral resources

As at December 31, 2012 (100% – only the last column shows our share)

Measured and indicated

(tonnes in thousands; pounds in millions)

		MEASURED						INDICATED						TOTAL MEASURED AND INDICATED
PROPERTY	MINING METHOD	TONNES		GRADE % U3O8		CONTENT (lbs U3O8)		TONNES		GRADE % U3O8		CONTENT (lbs U3O8)		TONNES		GRADE % U3O8		CONTENT (lbs U3O8)		CAMECO’S SHARE (lbs U3O8)
McArthur River	underground		81.7		4.83		8.7		15.5		9.97		3.4		97.2		5.65		12.1		8.5
Cigar Lake	underground		18.9		1.68		0.7		25.5		2.71		1.5		44.4		2.27		2.2		1.1
Kintyre	open pit								4,315.4		0.58		55.2		4,315.4		0.58		55.2		38.7
Rabbit Lake	underground								485.6		0.60		6.4		485.6		0.60		6.4		6.4
Dawn Lake	open pit, underground								347.0		1.69		12.9		347.0		1.69		12.9		7.4
Millennium	underground								742.7		4.16		68.2		742.7		4.16		68.2		47.7
Phoenix	underground								152.4		15.60		52.3		152.4		15.60		52.3		15.7
Tamarack	underground								183.8		4.42		17.9		183.8		4.42		17.9		10.3
Inkai	ISR								28,992.7		0.08		48.6		28,992.7		0.08		48.6		28.0
Gas Hills-Peach	ISR		1,964.2		0.08		3.4		6,857.9		0.12		18.8		8,822.1		0.11		22.2		22.2
North Butte-Brown Ranch	ISR								7,248.9		0.08		12.3		7,248.9		0.08		12.3		12.3
Smith Ranch-Highland	ISR		2,324.5		0.10		5.2		14,618.1		0.06		17.8		16,942.6		0.06		23.0		23.0
Crow Butte	ISR								2,595.1		0.21		12.2		2,595.1		0.21		12.2		12.2
Ruby Ranch	ISR								2,215.3		0.08		4.1		2,215.3		0.08		4.1		4.1
Ruth	ISR								1,080.5		0.09		2.1		1,080.5		0.09		2.1		2.1
Shirley Basin	ISR		89.2		0.16		0.3		1,638.2		0.11		4.1		1,727.4		0.12		4.4		4.4
Total			4,478.5		—		18.3		71,514.6		—		337.8		75,993.1		—		356.1		244.1

102 CAMECO CORPORATION

Inferred

(tonnes in thousands; pounds in millions)

PROPERTY	MINING METHOD	TONNES		GRADE % U3O8		CONTENT (lbs U3O8)		CAMECO’S SHARE (lbs U3O8)
McArthur River	underground		329.4		7.78		56.5		39.5
Cigar Lake	underground		373.4		12.01		98.9		49.5
Kintyre	open pit		950.2		0.46		9.6		6.7
Rabbit Lake	underground		375.0		1.24		10.3		10.3
Millennium	underground		191.5		5.29		22.3		15.6
Phoenix	underground		11.6		29.80		7.6		2.3
Tamarack	underground		45.6		1.02		1.0		0.6
Inkai	ISR		254,606.1		0.05		255.0		146.6
Gas Hills-Peach	ISR		861.5		0.07		1.3		1.3
North Butte-Brown Ranch	ISR		594.3		0.06		0.8		0.8
Smith Ranch-Highland	ISR		6,404.0		0.05		6.6		6.6
Crow Butte	ISR		2,114.6		0.12		5.4		5.4
Ruby Ranch	ISR		56.2		0.14		0.2		0.2
Ruth	ISR		210.9		0.08		0.4		0.4
Shirley Basin	ISR		508.0		0.10		1.1		1.1
Total			267,632.3		—		477.0		286.9

Notes

ISR – in situ recovery

Mineral resources do not include amounts that have been identified as mineral reserves.

Mineral resources do not have demonstrated economic viability. Totals may not add up due to rounding.

MANAGEMENT’S DISCUSSION AND ANALYSIS 103

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 2012, we paid PACL $57 million for construction and contracting services (2011 – $63 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

Because of 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. We believe the following critical accounting estimates reflect the more significant judgments used in the preparation of our financial statements.

DECOMMISSIONING AND RECLAMATION

We are required to estimate the cost of decommissioning and reclamation for each operation, but we normally do not incur these costs until an asset is nearing the end of its useful life. Regulatory requirements and decommissioning methods could change during that time, making our actual costs different from our estimates. A significant change in these costs or in our mineral reserves could have a material impact on our net earnings and financial position.

PROPERTY, PLANT AND EQUIPMENT

We depreciate property, plant and equipment primarily using the unit of production method, where the carrying value is reduced as resources are depleted. A change in our mineral reserves would change our depreciation expenses, and such a change could have a material impact on amounts charged to earnings.

We assess the carrying values of property, plant and equipment and goodwill every year, or more often if necessary. If we determine that we cannot recover the carrying value of an asset or goodwill, we write off the unrecoverable amount against current earnings. We base our assessment of recoverability on assumptions and judgments we make about future prices, production costs, our requirements for sustaining capital and our ability to economically recover mineral reserves. A material change in any of these assumptions could have a significant impact on the potential impairment of these assets.

TAXES

When we are preparing our financial statements, we estimate taxes in each jurisdiction we operate in, taking into consideration different tax rates, non-deductible expenses, valuation of deferred tax assets, changes in tax laws and our expectations for future results.

We base our estimates of deferred income taxes on temporary differences between the assets and liabilities we report in our financial statements, and the assets and liabilities determined by the tax laws in the various countries we operate in. We record deferred income taxes in our financial statements based on our estimated future cash flows, which includes estimates of non-deductible expenses. If these estimates are not accurate, there could be a material impact on our net earnings and financial position.

104 CAMECO CORPORATION

Controls and procedures

We have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2012, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.

Management, including our CEO and our CFO, supervised and participated in the evaluation, and concluded that our disclosure controls and procedures are effective to provide a reasonable level of assurance that the information we are required to disclose in reports we file or submit under securities laws is recorded, processed, summarized and reported accurately, and within the time periods specified. It should be noted that, while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect the disclosure controls and procedures or internal control over financial reporting to be capable of preventing all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Management, including our CEO and our CFO, is responsible for establishing and maintaining internal control over financial reporting and conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2012. We have not made any change to our internal control over financial reporting during the 2012 fiscal year that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

New standards and interpretations not yet adopted

A number of new standards, interpretations and amendments to existing standards are not yet effective for the year ended December 31, 2012, and have not been applied in preparing these consolidated financial statements. The following standards, amendments to and interpretations of existing standards have been published and are mandatory for our accounting periods beginning on or after January 1, 2013, unless otherwise noted.

FINANCIAL INSTRUMENTS

In October 2010, the International Accounting Standards Board (IASB) issued IFRS 9, Financial Instruments (IFRS 9). This standard is part of a wider project to replace IAS 39, Financial Instruments: Recognition and Measurement (IAS 39). IFRS 9 replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The basis of classification depends on the entity’s business model and the contractual cash flow characteristics of the financial asset or liability. The guidance in IAS 39 on impairment of financial assets and hedge accounting continues to apply. IFRS 9 is effective for annual periods beginning on or after January 1, 2015, with early adoption permitted. We do not intend to early adopt IFRS 9. The extent of the impact of adoption of IFRS 9 has not yet been determined.

CONSOLIDATED FINANCIAL STATEMENTS

In May 2011, the IASB issued IFRS 10, Consolidated Financial Statements (IFRS 10). This standard establishes principles for the presentation and preparation of consolidated financial statements when an entity controls one or more other entities. IFRS 10 defines the principle of control and establishes control as the basis for determining which entities are consolidated in the consolidated financial statements. We performed a review of our investees and determined that adoption of this standard will not have a material impact on our financial statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS 105

JOINT ARRANGEMENTS

In May 2011, the IASB issued IFRS 11, Joint Arrangements (IFRS 11). This standard establishes principles for financial reporting by parties to a joint arrangement. IFRS 11 requires a party to assess the rights and obligations arising from an arrangement in determining whether an arrangement is either a joint venture or a joint operation. Joint ventures are to be accounted for using the equity method while joint operations will continue to be accounted for using proportionate consolidation. We performed a review of all arrangements and determined that our interest in BPLP constitutes a joint venture. As a result we will no longer recognize our proportionate share of the revenue, expenses, assets, liabilities and cash flows of BPLP. Instead, we will recognize our share of net assets and earnings on a single line in the consolidated statements of financial position and consolidated statements of earnings, with partner distributions being recognized in the consolidated statements of cash flows.

DISCLOSURE OF INTERESTS IN OTHER ENTITIES

In May 2011, the IASB issued IFRS 12, Disclosure of Interests in Other Entities (IFRS 12). This standard applies to entities that have an interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. IFRS 12 integrates and makes consistent the disclosure requirements for a reporting entity’s interest in other entities and presents those requirements in a single standard. The adoption of IFRS 12 is expected to increase the current level of disclosure of interests in other entities.

FAIR VALUE MEASUREMENT

In May 2011, the IASB issued IFRS 13, Fair Value Measurement (IFRS 13). This standard provides additional guidance where IFRS requires fair value to be used. IFRS 13 defines fair value, sets out in a single standard a framework for measuring fair value and establishes the required disclosures about fair value measurements. We do not expect the adoption of IFRS 13 to have a material impact on the financial statements.

EMPLOYEE BENEFITS

In June 2011, the IASB issued an amended version of IAS 19, Employee Benefits (IAS 19). This amendment eliminates the ‘corridor method’ of accounting for defined benefit plans. Revised IAS 19 also accelerates the recognition of past service costs and requires a net interest approach. In addition, it streamlines the presentation of changes in assets and liabilities arising from defined benefit plans, and enhances the disclosure requirements. We intend to retrospectively adopt the amendments in our financial statements. It is expected that the use of the net interest approach, which is the use of the discount rate as opposed to the expected long-term rate of return on plan assets, will have the greatest impact on the financial results. While this change will not materially impact our plans, it is expected to increase our share of the BPLP employee benefit costs for 2013 by approximately $24 million (2012 – $17 million). The difference between the actual return on plan assets and the discount rate will be recognized in other comprehensive income.

PRESENTATION OF OTHER COMPREHENSIVE INCOME (OCI)

In June 2011, the IASB issued an amended version of IAS 1, Presentation of Financial Statements (IAS 1). This amendment is effective for annual periods beginning on or after July 1, 2012 and requires companies preparing financial statements in accordance with IFRS to group together items within OCI that may be reclassified to earnings. Revised IAS 1 also reaffirms existing requirements that items in OCI and earnings should be presented as either a single statement or two consecutive statements. The adoption of these amendments to IAS 1 will not have a material impact on the financial statements.

106 CAMECO CORPORATION

FINANCIAL ASSETS AND FINANCIAL LIABILITIES

In December 2011, the IASB issued amendments to IAS 32, Financial Instruments: Presentation (IAS 32) and IFRS 7, Financial Instruments: Disclosures (IFRS 7). The amendments are effective for periods beginning on or after January 1, 2013 for IFRS 7 and January 1, 2014 for IAS 32 and are to be applied retrospectively. These amendments clarify matters regarding offsetting financial assets and financial liabilities as well as related disclosure requirements. We intend to adopt the amendments to IFRS 7 in our financial statements for the annual period beginning on January 1, 2013, and the amendments to IAS 32 in our financial statements for the annual period beginning January 1, 2014 and do not expect the amendments to have a material impact on the financial statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS 107