EX-99.3 4 d887074dex993.htm EX-99.3

EXHIBIT 99.3

Cameco Corporation

2014 Management’s Discussion and Analysis

February 9, 2015

Management’s discussion and analysis

February 9, 2015

6 |  | 2014 PERFORMANCE HIGHLIGHTS
9 |  | MARKET OVERVIEW
12 |  | 2014 MARKET DEVELOPMENTS
14 |  | OUR STRATEGY
18 |  | SUSTAINABLE DEVELOPMENT
22 |  | FINANCIAL RESULTS
50 |  | OUR OPERATIONS AND PROJECTS
79 |  | MINERAL RESERVES AND RESOURCES
84 |  | ADDITIONAL INFORMATION
87 |  | 2014 CONSOLIDATED FINANCIAL STATEMENTS

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, 2014. The information is based on what we knew as of February 5, 2015.

We encourage you to read our audited consolidated 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.

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

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

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

Caution about forward-looking information

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

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

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

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

• |  | It is based on a number of material assumptions, including those we have listed on page 3, which may prove to be incorrect.

• |  | Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks on pages 2 and 3. We recommend you also review our annual information form, which includes a discussion of other material risks that could cause actual results to differ significantly from our current expectations.

• |  | Forward-looking information is designed to help you understand management’s current views of our near and longer term prospects, and it may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws.

Examples of forward-looking information in this MD&A

• |  | our expectations about 2015 and future global uranium supply, consumption, demand, contracting volumes, number of reactors and nuclear generating capacity, including the discussion under the headings Market overview and 2014 market developments

• |  | the discussion under the heading Our strategy

• |  | our 2015 objectives

• |  | our expectations for uranium deliveries in the first quarter and for the balance of 2015

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

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

• |  | future tax payments and rates

• |  | our price sensitivity analysis for our uranium segment

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

• |  | our expectations for 2015, 2016 and 2017 capital expenditures

• |  | our expectation that in 2015 we will continue to comply with all the covenants in our unsecured revolving credit facility

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

• |  | our mineral reserve and resource estimates

Material risks

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

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

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

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

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

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

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

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

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

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

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

| • |  | we are affected by political risks

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

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

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

• |  | our uranium suppliers fail to fulfil delivery commitments

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

• |  | our Cigar Lake development, mining or production plans are delayed or do not succeed, including as a result of any difficulties with the jet boring mining method or freezing the deposit to meet production targets, the third jet boring machine does not go into operation on schedule in 2015 or operate as expected, or any difficulties with the McClean Lake mill modifications or expansion or milling of Cigar Lake ore

• |  | we are unable to obtain an extension to the term of Inkai’s block 3 exploration licence, which expires in July 2015

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

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

Material assumptions

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

| • |  | our expectations regarding the demand for uranium, the construction of new nuclear power plants and the relicensing of existing nuclear power plants not being more adversely affected than expected by changes in regulation or in the public perception of the safety of nuclear power plants

| • |  | our expected production level and production costs

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

| • |  | our expectations regarding spot prices and realized prices for uranium, and other factors discussed on page 33, Price sensitivity analysis: uranium segment

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

| • |  | our expectations about the outcome of disputes with tax authorities

| • |  | our decommissioning and reclamation expenses

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

| • |  | the geological, hydrological and other conditions at our mines

| • |  | our McArthur River development, mining and production plans succeed

| • |  | our Cigar Lake development, mining and production plans succeed, including the third jet boring machine goes into operation on schedule in 2015 and operates as expected, the jet boring mining method works as anticipated, and the deposit freezes as planned

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

| • |  | the term of Inkai’s block 3 exploration licence does not expire in July 2015 and is instead extended

| • |  | our ability to continue to supply our products and services in the expected quantities and at the expected times

| • |  | our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals

| • |  | our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents or other development or operating risks

MANAGEMENT’S DISCUSSION AND ANALYSIS 3

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MANAGEMENT’S DISCUSSION AND ANALYSIS 5

2014 performance highlights

Market conditions remained challenging in 2014, with little change from the previous year. However, Cameco performed well, navigating the near term challenges, while continuing to prepare for the positive long-term growth we see coming in the industry. We exceeded our production guidance, delivered on our financial guidance, and achieved record annual revenue from our uranium segment with a record annual realized price.

Strong financial performance

Our financial results remained strong in 2014:

• |  | annual revenue of $2.4 billion

• |  | annual gross profit of $638 million

• |  | record annual revenue of $1.8 billion from our uranium segment based on sales of 32.5 million pounds

• |  | record annual average realized price of $52.37 (Cdn) per pound in our uranium segment

Net earnings attributable to our equity holders (net earnings) in 2014 were $185 million compared to $318 million in 2013. This $133 million decrease in net earnings was the result of:

• |  | write-downs totalling $327 million of our investments in Eagle Point mine assets at Rabbit Lake – $126 million, GE-Hitachi Global Laser Enrichment (GLE) – $184 million, and GoviEx Uranium Inc. (Goviex) – $17 million

• |  | no earnings from Bruce Power Limited Partnership (BPLP), which we divested in the first quarter of 2014

• |  | the write-off of $41 million of assets under construction as a result of changes made to the scope of a number of projects

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

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

• |  | lower earnings in our fuel services segment as a result of a decrease in sales volumes and higher unit cost of sales

• |  | higher losses on foreign exchange derivatives due to the weakening of the Canadian dollar

partially offset by:

• |  | a $127 million gain on the sale of our interest in BPLP

• |  | higher earnings in our uranium segment due to higher average realized prices

• |  | a favourable settlement of $66 million in a dispute regarding a long-term supply contract with a utility customer

• |  | lower exploration costs due to a more focused effort on our core projects in Saskatchewan, with decreases in activity elsewhere, particularly in Australia and at Inkai

• |  | higher tax recoveries resulting from pre-tax losses in Canada, see Income taxes on page 27 for details

HIGHLIGHTS DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |  | 2014 |  |  | 2013 |  |  | CHANGE |
Revenue |  |  | 2,398 |  |  |  | 2,439 |  |  |  | (2 | )%
Gross profit |  |  | 638 |  |  |  | 607 |  |  |  | 5 | %
Net earnings attributable to equity holders |  |  | 185 |  |  |  | 318 |  |  |  | (42 | )%
$ per common share (diluted) |  |  | 0.47 |  |  |  | 0.81 |  |  |  | (42 | )%
Adjusted net earnings (non-IFRS, see page 24) |  |  | 412 |  |  |  | 445 |  |  |  | (7 | )%
$ per common share (adjusted and diluted) |  |  | 1.04 |  |  |  | 1.12 |  |  |  | (7 | )%
Cash provided by continuing operations (after working capital changes) |  |  | 480 |  |  |  | 524 |  |  |  | (8 | )%

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Solid progress in our uranium segment this year

In our uranium segment, we exceeded our annual production expectations, and realized a number of successes at our mining operations. Key highlights:

• |  | annual production of 23.3 million pounds—2% higher than the guidance we provided in our 2014 third quarter MD&A

• |  | record quarterly production of 8.2 million pounds in the fourth quarter—9% higher than in 2013, largely due to record quarterly production from the Key Lake mill

• |  | produced the first packaged uranium concentrate from the Cigar Lake mine and AREVA’s McClean Lake mill

• |  | the Canadian Nuclear Safety Commission (CNSC) approved the Environmental Assessment (EA) for the Key Lake extension project, which includes permission to produce up to 25 million pounds (100%) per year at Key Lake mill. The CNSC also granted an annual production limit increase at McArthur River, allowing the mine to produce up to 21 million pounds (100%) per year.

• |  | in October, unionized employees at McArthur River and Key Lake accepted a new four-year contract, ending a labour dispute that resulted in an 18-day shutdown of the operations

We also continued to advance our exploration activities, spending $4 million on six brownfield exploration projects, $6 million on our projects under evaluation in Australia, and $5 million for resource definition at Inkai and at our US operations. We spent about $32 million on regional exploration programs, mostly in Saskatchewan and Australia.

Updates on our other segments and investments

In response to weak market conditions for UF6, we decided to reduce our planned 2014 production at Port Hope and terminate our toll-conversion agreement with SFL. As a result, production in our fuel services segment was lower than our plan at the beginning of the year, and 22% lower than in 2013.

We sold our 31.6% limited partnership interest in BPLP and related entities to BPC Generation Infrastructure Trust, one of the limited partners in BPLP, for $450 million. The sale closed on March 27, 2014, and we began accounting for the sale as of January 1, 2014.

In 2014, the majority partner of GLE decided to significantly reduce funding to GLE, which required us to review the value of our 24% interest in the asset. As a result, we wrote-down the full value of our investment and recorded a charge of $184 million in the third quarter. GLE is continuing its testing activities and engineering design work for a commercial facility, though at a slower pace. Negotiations are ongoing with the US Department of Energy (DOE) for the sale of its depleted uranium hexafluoride inventory. If negotiations are successful, we expect that definitive agreements with GLE would follow.

MANAGEMENT’S DISCUSSION AND ANALYSIS 7

HIGHLIGHTS |  |  |  | 2014 |  |  | 2013 |  |  | CHANGE |
Uranium |  | Production volume (million lbs) |  |  | 23.3 |  |  |  | 23.6 |  |  |  | (1 | )%
|  | Sales volume (million lbs) 1 |  |  | 33.9 |  |  |  | 32.8 |  |  |  | 3 | %
|  | Average realized price ($US/lb) |  |  | 47.53 |  |  |  | 48.35 |  |  |  | (2 | )%
|  | ($Cdn/lb) |  |  | 52.37 |  |  |  | 49.81 |  |  |  | 5 | %
|  | Revenue ($ millions) 1 |  |  | 1,777 |  |  |  | 1,633 |  |  |  | 9 | %
|  | Gross profit ($ millions) |  |  | 602 |  |  |  | 550 |  |  |  | 9 | %
Fuel services |  | Production volume (million kgU) |  |  | 11.6 |  |  |  | 14.9 |  |  |  | (22 | )%
|  | Sales volume (million kgU)2 |  |  | 15.5 |  |  |  | 17.6 |  |  |  | (12 | )%
|  | Average realized price ($Cdn/kgU) |  |  | 19.70 |  |  |  | 18.12 |  |  |  | 9 | %
|  | Revenue ($ millions) 2 |  |  | 306 |  |  |  | 319 |  |  |  | (4 | )%
|  | Gross profit ($ millions) |  |  | 38 |  |  |  | 52 |  |  |  | (27 | )%
NUKEM |  | Sales volume U3O8 (million lbs) 3 |  |  | 8.1 |  |  |  | 8.9 |  |  |  | (9 | )%
|  | Average realized price ($Cdn/lb) |  |  | 44.90 |  |  |  | 42.26 |  |  |  | 6 | %
|  | Revenue ($ millions) 3 |  |  | 349 |  |  |  | 465 |  |  |  | (25 | )%
|  | Gross profit ($ millions) |  |  | 22 |  |  |  | 20 |  |  |  | 10 | %

1 | Includes sales of 1.4 million pounds and revenue of $48 million between our uranium, fuel services and NUKEM segments in 2014.

2 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (0.5 million kgU in sales and revenue of $4 million in 2014, 0.7 million kgU in sales and revenue of $6 million in 2013).

3 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (1.1 million pounds in sales and revenue of $43 million in 2014, 0.6 million pounds in sales and revenue of $23 million in 2013).

SHARES AND STOCK OPTIONS OUTSTANDING

At February 5, 2015, we had:

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

• |  | 8,313,451 stock options outstanding, with exercise prices ranging from $19.37 to $54.38

DIVIDEND POLICY

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

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Market overview

The world needs energy

The nuclear story is a growth story. Today, there are 2 billion people on the planet without access to electricity, or only limited access, and world population is expected to increase by another 2 billion by 2050. This is driving a continued and substantial increase in global energy demand. Electricity is one of the greatest contributors to quality of life, and countries with rapidly expanding population and economies, like China, India, and those in the Middle East, are trying to catch up. They’re adding capacity to their grids to provide the electricity needed to support their growth.

Nuclear – an integral part of the energy mix

Nuclear power is a safe, clean, reliable, affordable and, most importantly, baseload energy source. The areas of the world where we’re seeing the most growth in new nuclear construction are in regions where baseload power is needed—that fundamental, 24-hour power that is required to have healthcare, education, transportation and communications systems.

But it’s also important to provide that energy reliably and affordably. Nuclear reactors can run on a single load of fuel for about 18 months, helping to shield utilities from possible fuel cost swings and supply interruptions.

Reactors – gigawatt growth

That’s why, today, we see billions of dollars being invested in nuclear around the world: about 70 reactors are under construction right now, and some existing plants are adding capacity through uprates. By 2024, we expect over 100 gigawatts of nuclear power, or about 80 net new reactors, to be added to the world’s grids, with even more growth expected outside that timeframe.

MANAGEMENT’S DISCUSSION AND ANALYSIS 9

China continues to lead the way with 26 reactors under construction. India, Russia, South Korea and the United States are also building new reactors. Of the reactors under construction today, if startups occur as planned, 45 of those units (about 46 gigawatts) could be online over the next three years.

Elsewhere, the United Kingdom (UK) government is maintaining its commitment to nuclear energy as a source of emissions-free energy. Critical milestones have been reached, allowing new build plans to move forward. In addition, several previously non-nuclear countries are moving ahead with their reactor construction programs or considering adding nuclear to their energy mix in the future. Construction continues on three of four planned units in the United Arab Emirates (UAE). Turkey is also moving forward with plans to build eight new reactors. Belarus, Saudi Arabia, Vietnam, Bangladesh, Poland and Jordan are continuing their plans to proceed with nuclear power development.

More reactors means more demand for uranium

Today, annual uranium consumption sits at around 155 million pounds. With the growth in reactor construction, we expect that to grow to around 230 million pounds per year by 2024—an average annual growth of 4%. This does not include the strategic inventory building that usually occurs with new reactor construction, which would suggest further growth in demand. So, over the long term, we see very strong growth in the demand for the products that we supply.

Can supply keep up?

Over the long term, while demand is increasing, supply, without new investment, is expected to decrease, resulting in the possibility of a widening gap between supply and demand.

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There is already a gap between the uranium consumed by reactors and the uranium produced from the world’s mines, which has been the case for many years. That gap has been bridged by secondary supplies—uranium in various forms that is already out of the ground and sitting in stockpiles around the world. Today, about 20% of global supply comes from secondary sources, but those stockpiles are being drawn down, and are expected to contribute less and less over time. This means that more primary production will be needed from uranium mines—in fact, we estimate about 15% of total supply required over the next decade will need to come from new mines that are not yet in development.

But that could be difficult. In general, new mines are difficult to bring on in a timely manner. The long lead nature of mine development means our industry is not able to respond quickly to sudden increases in demand or significant supply interruptions. Bringing on and ramping up a significant new production centre can take between seven and 10 years.

Adding to the challenge are the number of new projects being cancelled or delayed, and the existing production being shelved due to the low uranium prices that have persisted since the 2011 events at the Fukushima-Daiichi nuclear power plant in Japan. Today’s spot and term uranium prices are not high enough to incent new mine production and, in some cases, not high enough to keep current mines in operation. While some new mines may be brought on regardless of price as a result of sovereign interests, overall, we expect supply to decrease over time due to the global lack of investment.

Today – little demand, a lot of supply

Today, the uranium market is in a state of oversupply, and there are a number of factors contributing: primary supply continues to perform relatively well; enrichers are underfeeding their plants in reaction to excess enrichment capacity, which creates another source of uranium that’s being put onto the spot market; and Japanese reactors remain idled, meaning their inventories continue to grow. We do not believe those inventories are coming to market, but it removes Japanese utilities from the market as buyers for the time being.

In addition, market activity is much lighter than it has been in the past. Utilities are well covered in their fuel requirements and are not under pressure to contract for more. They have time to wait it out to see if uranium prices continue to decrease. So far, this strategy has paid off for them. Similarly, existing suppliers appear reluctant to enter into meaningful contract volumes at current prices. The result has been very low levels of contracting over the past two years. For example, in a typical year, we’d expect to see an average of 175 million pounds per year committed under long-term contracts; in 2013 Ux estimated just 20 million pounds were contracted, and in 2014, about 82 million pounds. However, consumption is a fairly simple and constant equation based on the fuel needs of operating reactors. So, if contracting is not happening now, it will have to later; the demand has just been pushed further out in time.

MANAGEMENT’S DISCUSSION AND ANALYSIS 11

2014 market developments

SUPPLY AND DEMAND

Market conditions remained depressed in 2014. In particular, the slower than expected pace of Japanese reactor restarts and generally sluggish reactor construction and start-ups globally led to demand erosion. Unlike 2013, we did observe supply contraction during the year as several existing production centres were shut down and some uranium projects were delayed or cancelled in response to poor market conditions. However, this was more than offset by demand erosion and steady flows of secondary supply. The impact of these conditions was the continuation of the inventory overhang and depressed prices resulting from the 2011 events at the Fukushima-Daiichi nuclear power plant in Japan.

CONTRACTING

Market contracting activity was modest. Spot volumes were normal, but long-term contracting was well below historical averages and current consumption levels—about half of current annual reactor consumption estimates, albeit higher than in 2013. Long-term contracting is a key factor in the timing of market recovery, and its pace will depend on the respective coverage levels, market views and risk appetite of both buyers and sellers.

JAPAN

There were several positive indications for the long term in 2014. Japanese utilities and the Nuclear Regulatory Authority (NRA) began implementing the regulatory process required for reactor restarts; currently, 11 restart applications have been submitted by 11 utilities covering 21 reactors. The frontrunners are the two Sendai reactors, which appear poised for restart in the first half of 2015 following a few final regulatory confirmations and safety checks. Beyond Sendai, two Takahama units were granted preliminary safety approval from the NRA in late-2014, moving these reactors into the final regulatory approval stages. More broadly, we continue to see a high degree of confidence from Japanese utilities who are spending billions of dollars on plant upgrades in anticipation of a positive restart environment.

OTHER REGIONS

China’s remarkable nuclear growth program remains on track and the UK continues to be a bright spot for the industry as plans for new reactor construction move forward. India, Russia and South Korea are also among several key regions growing their nuclear generation fleet.

In 2014, growth was tangible as five reactors came online: three in China, one in Argentina, and one in Russia. It was also exciting to see two emerging nuclear countries start construction on reactors: one in the UAE and one in Belarus.

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Industry prices

In 2014, the spot price declined from $40 (US) per pound to a nine-year low of about $28 (US) per pound, but managed to average around $33 (US) for the year. Utilities continue to be well covered under existing contracts, and given the current uncertainties in the market, we expect they and other market participants will continue to be opportunistic in their buying. As a result, contracting over the next 12 months should remain somewhat discretionary.

|  | 2014 |  |  | 2013 |  |  | CHANGE |
Uranium ($US/lb U3O8) 1 |  |  |  |  |  |  |  |  |  |  |  |
Average spot market price |  |  | 33.21 |  |  |  | 38.17 |  |  |  | (13 | )%
Average long-term price |  |  | 46.46 |  |  |  | 54.13 |  |  |  | (14 | )%
Fuel services ($US/kgU as UF6)1 |  |  |  |  |  |  |  |  |  |  |  |
Average spot market price |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  | 7.63 |  |  |  | 9.60 |  |  |  | (21 | )%
Europe |  |  | 7.97 |  |  |  | 10.07 |  |  |  | (21 | )%
Average long-term price |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  | 16.00 |  |  |  | 16.50 |  |  |  | (3 | )%
Europe |  |  | 17.00 |  |  |  | 17.17 |  |  |  | (1 | )%
Note: the industry does not publish UO2 prices. |  |  |  |  |  |  |  |  |  |  |  |

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 13

Our strategy

Positioned for success

Our strategy is set within the context of a challenging market environment, which we expect to give way to strong long-term fundamentals driven by increasing population and electricity demand.

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

URANIUM

Our primary focus is on uranium production. It is the biggest value driver of the nuclear fuel cycle and our business. We have the ability to flex our production according to market conditions in order to return the best value possible. See Uranium – production overview on page 53 for additional details.

FUEL SERVICES

Our fuel services division is a source of profit and supports our uranium segment while allowing us to vertically integrate across the fuel cycle. Our focus is on maintaining and optimizing profitability.

ENRICHMENT

We continue to explore opportunities in the second largest value driver of the fuel cycle.

NUKEM

NUKEM’s activities provide a source of profit and give us insight into market dynamics.

Our mission is to energize

Our purpose is to bring the multiple benefits of nuclear energy to the world. We want to be the supplier, partner, investment and employer of choice in the nuclear industry.

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Capital allocation – focus on value

Delivering returns to our long-term shareholders is a top priority. We continually evaluate our investment options to ensure we allocate our capital in a way that we believe will:

• |  | create the greatest long-term value for our shareholders

• |  | allow us to maintain our investment grade rating

• |  | ensure we execute on our dividend policy

We start by determining how much cash we have to invest (investable capital), which is based on our expected cash flow from operations minus expenses we consider to be a higher priority, such as dividends and financing costs, and could include others. This investable capital can be reinvested in the company or returned to shareholders.

REINVESTMENT

Before investable capital is reinvested in sustaining, capacity replacement or growth, each investment must demonstrate it can meet the required risk-adjusted return criteria, and we must identify at the corporate level the expected impact on cash flow, earnings and the balance sheet. All project risks must be identified, including the risks of not investing. Allocation of capital only occurs once an investment has cleared these hurdles.

This may result in some opportunities being held back in favour of higher return investments, and should allow us to generate the best return on investment decisions when faced with multiple prospects, while also controlling our costs. If there are not enough good growth prospects internally or externally, this may also result in residual investable capital, which we would then consider returning directly to shareholders.

RETURN

If we determine the best use of cash is to return it to shareholders, we can do that through a share repurchase or dividend—either a one-time special dividend or a dividend growth policy. When deciding between these options, we consider a number of factors, including generation of excess cash, growth prospects for the company, growth prospects for the industry, and the nature of the excess cash.

Share buyback: If we were generating excess cash while there were little or no growth prospects for the company or the industry, then a share buyback might make sense. However, our current view is that the long-term fundamentals for Cameco and the industry remain strong.

Dividend: We view our dividend as a priority. Therefore, any change to our dividend policy must be carefully considered with a view to long-term sustainability. Currently, the conditions in the uranium market do not provide us with the level of certainty we require to implement changes to our dividend policy.

Marketing strategy – balanced contract portfolio

As with our corporate strategy and approach to capital allocation, the purpose of our marketing strategy is to deliver value. Our approach is to secure a solid base of earnings and cash flow by maintaining a balanced contract portfolio that optimizes our realized price.

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. We sell uranium and fuel services directly to nuclear utilities around the world as uranium concentrates, UO2, UF6, conversion services or fuel fabrication. We have an extensive portfolio of long-term sales contracts which reflects the long-term, trusting relationships we have with our customers.

In addition, we are active in the spot market, buying and selling uranium when it is beneficial for us. Our NUKEM business segment enhances our ability to participate, as they are one of the world’s leading traders of uranium and uranium-related products. We undertake activity in the spot market prudently, looking at the spot price and other business factors to decide whether it is appropriate to purchase or sell into the spot market. Not only is this activity a source of profit, it gives us insight into underlying market fundamentals.

MANAGEMENT’S DISCUSSION AND ANALYSIS 15

OPTIMIZING REALIZED PRICE

We try to maximize our realized price by signing contracts with terms between five 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.

Because we deliver large volumes of uranium every year, our net earnings and operating cash flows are affected by changes in the uranium price. Market prices are influenced by the fundamentals of supply and demand, geopolitical events, disruptions in planned supply and other market factors.

LONG-TERM CONTRACTING

We target a ratio of 40% fixed-pricing and 60% market-related pricing in our portfolio of long-term contracts. This is a balanced and flexible approach that allows us to adapt to market conditions and put a floor on our average realized price, reduce the volatility of our future earnings and cash flow, and deliver the best value to shareholders over the long term. The ratio is also consistent with the contracting strategy of our customers.

Over time, this strategy has allowed us to add increasingly favourable contracts to our portfolio that will enable us to participate in increases in market prices in the future.

Fixed price contracts: are typically based on the industry long-term price indicator at the time the contract is accepted and escalated over the term of the contract.

Market-related contracts: are different from fixed-price contracts in that they may be based on either the spot price or the long-term price, and that price is as quoted at the time of delivery rather than at the time the contract is accepted. These contracts also often include floor prices and some include ceiling prices, both of which are also escalated over the term of the contract.

Fuel services contracts: the majority of our fuel services contracts are at a fixed price per kgU, escalated over the term of the contract, and reflect the market at the time the contract is accepted.

CONTRACT PORTFOLIO STATUS

Currently, we are heavily committed under long-term uranium contracts through 2018, so we are being selective when considering new commitments. We have commitments to sell approximately 200 million pounds of U3O8 with 43 customers worldwide in our uranium segment, and commitments to sell approximately 70 million kilograms as UF6 conversion with 36 customers worldwide in our fuel services segment.

Customers – U3O8:

Five largest customers account for 50% of commitments

16 CAMECO CORPORATION

Customers – UF6 conversion:

• |  | Five largest customers account for 56% of commitments

MANAGING OUR CONTRACT COMMITMENTS

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

• |  | from our existing production

• |  | through purchases under long-term agreements and in the spot market

• |  | from our existing inventory

We allow sales volume to vary year-to-year depending on:

• |  | the level of sales commitments in our long-term contract portfolio (the annual average sales commitments over the next five years in our uranium segment is 27 million pounds, with commitment levels through 2018 higher than in 2019)

• |  | our production volumes, including from the rampup of Cigar Lake and from planned increases at McArthur River/Key Lake

• |  | purchases under existing and/or new arrangements

• |  | discretionary use of inventories

• |  | market opportunities

Focusing on cost efficiency

PRODUCTION COSTS

In order to operate efficiently and cost-effectively, we manage operating costs and improve plant reliability by prudently investing in production infrastructure, new technology and business process improvements. Like all mining companies, our uranium segment is affected by the rising cost of inputs such as labour and fuel.

As we ramp up to full production at Cigar Lake, we expect the initial cash costs to be higher, which is expected to increase our average unit cost of sales.

MANAGEMENT’S DISCUSSION AND ANALYSIS 17

Operating costs in our fuel services segment are mainly fixed. In 2014, labour accounted for about 54% of the total. The largest variable operating cost is for zirconium, followed by energy (natural gas and electricity), and anhydrous hydrogen fluoride.

PURCHASES AND INVENTORY COSTS

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

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

To determine our cost of sales, we calculate the average of all our sources of supply, including opening inventory, production and purchases. Therefore, to the extent the cost of our purchases are higher than the cost of our other sources of supply, we would expect our unit cost of sales to increase.

FINANCIAL IMPACT

The impact of these increased unit costs on our financial results is expected to be temporary. As greater certainty returns to the uranium market, based on our view that the market will transition from being supply-driven to being demand-driven, we expect uranium prices will rise to reflect the cost of bringing on new production to meet growing demand, which should have a positive impact on our average realized price.

In addition, as Cigar Lake reaches full production and the expansion at McArthur River/Key Lake is complete, our production will increase, which we expect will create more stability in the unit cost of sales for our uranium segment.

Sustainable development: A key part of our strategy

Social responsibility and environmental protection are top priorities for us, so much so that we have built them into our corporate objectives as measures of success: a safe, healthy and rewarding workplace, a clean environment, supportive communities, and outstanding financial performance. For us, sustainability isn’t an add-on for our company; it’s at the core of our company culture. It helps us:

• |  | build trust, credibility and corporate reputation

• |  | gain and enhance community support for our operations and plans

• |  | attract and retain employees

• |  | manage risk

• |  | drive innovation and continual improvement to build competitive advantage

Because they are so important, we aim to integrate sustainable development principles and practices at each level of our organization, from our overall corporate strategy to every aspect of our day-to-day operations.

SAFE, HEALTHY, REWARDING WORKPLACE

We are committed to living a strong safety culture, while looking to continually improve. As a result of this commitment, we have a long history of strong safety performance at our operations and across the organization.

2014 Highlights:

• |  | our total annual recordable injury rate decreased by 19% in 2014

• |  | continued low average dose of radiation to workers

• |  | won John T Ryan National Safety award for McArthur River mine

• |  | top employer awards

A CLEAN ENVIRONMENT

We are committed to being a leading environmental performer. We strive to be a leader not only by complying with legal requirements, but by keeping risks as low as reasonably achievable, including taking steps to prevent pollution.

18 CAMECO CORPORATION

We track our progress by monitoring our impacts on air, water and land near our operations, and by measuring the amount of energy we use and the amount of waste generated. We use this information to help identify opportunities to improve.

2014 Highlights:

• |  | decrease in treated water discharged to surface water

• |  | continued focus on maintaining excellent water discharge quality, with an effort to minimize increases to water withdrawal while increasing production at our facilities

SUPPORTIVE COMMUNITIES

Gaining the trust and support of our communities, indigenous people, governments and regulators is necessary to sustain our business. We earn support and trust through excellent safety and environmental performance, by proactively engaging our stakeholders in an open and transparent way, and by making a difference in communities wherever we operate.

2014 Highlights:

• |  | over $300 million in procurement from locally owned northern Saskatchewan companies

• |  | 794 local employees from northern Saskatchewan

• |  | no significant disputes related to land use or customary rights

• |  | community engagement activities at 100% of our operations

OUTSTANDING FINANCIAL PERFORMANCE

Long-term financial stability and profitability are essential to our sustainability as a company. We firmly believe that sound governance is the foundation for strong corporate performance.

2014 Highlights:

• |  | continue to achieve an average realized price that outperforms the market

• |  | ranked 25th out of 232 Canadian companies by Globe and Mail in governance practices

MONITORING AND MEASUREMENT

We take integration and measurement seriously. We have been producing a Sustainable Development Report since 2005, using the Global Reporting Initiative’s Sustainability Framework (GRI). It is our report card to our stakeholders. It tells them how we’re performing against globally recognized key indicators that measure our social, environmental and economic impacts in the areas that matter most to them. It provides information about our goals, where we’ve met, exceeded or struggled with them, and how we plan to do better. And in 2014 we also conducted a limited assurance of the report, carried out by Ernst & Young.

Aside from our commitment to the GRI, we manage and report on our sustainability initiatives in a number of ways:

• |  | all of our operating sites are ISO 14001 compliant, with the exception of the Cigar Lake mine, where we plan to seek compliance after we have achieved commercial production. Further, we have secured a corporate ISO 14001 registration and we are going to be taking steps to roll all of our sites under this registration;

• |  | we have participated in the Carbon Disclosure Project since 2006

Achievements

We are a four-time Gold award winner through the Progressive Aboriginal Relations program given out by the Canadian Council for Aboriginal Business. Also, in 2014, we secured approval to increase production at the McArthur River and Key Lake operation as a result of earning the confidence of our regulators, which includes their regard for the positive relationships we have with neighbouring communities in northern Saskatchewan. We are a leading employer of Indigenous peoples in Canada, and have procured over $3 billion in services from local suppliers in the region since 2004. And, we are proud to have been named one of Canada’s Best Diversity Employers, Top 100 Employers, and Saskatchewan’s Top Employers for five consecutive years.

We encourage you to review our SD report at cameco.com/about/sustainability which outlines our commitment to people and the environment in more detail.

MANAGEMENT’S DISCUSSION AND ANALYSIS 19

Measuring our results

There is no finish line when it comes to delivering on our strategic goals. We have a long-term commitment to constantly measure, evaluate and improve.

Each year, we set corporate objectives that are aligned with our strategic plan. These objectives fall under our four measures of success, and performance against specific targets under these objectives forms the foundation for a portion of annual employee and executive compensation. See our most recent management proxy circular for more information on how executive compensation is determined.

2014 OBJECTIVES1 |  | TARGET |  | RESULTS |  |  |  |
OUTSTANDING FINANCIAL PERFORMANCE
Earnings measures |  | Achieve targeted adjusted net earnings and cash flow from operations. |  | Exceeded |  | • |  | adjusted net earnings was higher than the target
|  |  |  |  |  | • |  | cash flow from operations was higher than the target
Capital management measures |  | Execute capital projects within scope, on time and on budget. |  | Substantially Achieved |  | • |  | the cost performance indicator was above the target level (under budget)
|  |  |  |  |  | • |  | the schedule performance indicator was below the threshold (behind schedule)
Cigar Lake |  | Achieve Jet Boring System (JBS) mining cycle times at Cigar Lake. |  | Exceeded |  | • |  | average JBS cycle times were better than targeted
SAFE, HEALTHY AND REWARDING WORKPLACE
Workplace safety |  | Strive for no injuries at all Cameco-operated sites and maintain a long-term downward trend in combined employee and contractor injury frequency and severity, and radiation doses. |  | Achieved |  | • |  | met our targeted safety measures
|  |  |  |  | • |  | injury rates trended downward across the company and met targets for the year
|  |  |  |  | • |  | average radiation doses remained low and stable
Rewarding workplace |  | Attract and retain the employees. |  | Substantially Achieved |  | • |  | overall turnover rate was better than target (lower turnover)
|  |  |  |  |  | • |  | turnover rate for new hires during the first year of employment was higher than the target (higher turnover)
CLEAN ENVIRONMENT
Improve environmental performance |  | Achieve a decreasing trend for environmental incidents. |  | Achieved |  | • |  | there were no significant environmental incidents in 2014
|  |  |  |  |  | • |  | reportable environmental incidents were within the range of targeted performance
SUPPORTIVE COMMUNITIES
Build stakeholder support |  | Meet our business development obligations under our Collaboration Agreements. |  | Substantially Achieved |  | • |  | site utilization of labour services in our Collaboration Agreements with stakeholder communities was below the target
|  |  |  |  |  | • |  | our environmental waste management scoping study was completed by the target date

1 | Detailed results for our 2014 corporate objectives and the related targets will be provided in our 2015 management proxy circular prior to our Annual Meeting of Shareholders on May 22, 2015.

20 CAMECO CORPORATION

2015 objectives

OUTSTANDING FINANCIAL PERFORMANCE

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

| • |  | Achieve capital project management targets and continue to ramp up production at Cigar Lake.

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 21

Financial results

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

23 |  | 2014 CONSOLIDATED FINANCIAL RESULTS
26 |  | OUTLOOK FOR 2015
34 |  | LIQUIDITY AND CAPITAL RESOURCES
39 |  | BALANCE SHEET
40 |  | 2014 FINANCIAL RESULTS BY SEGMENT
40 |  | URANIUM
42 |  | FUEL SERVICES
42 |  | NUKEM
44 |  | FOURTH QUARTER FINANCIAL RESULTS
44 |  | CONSOLIDATED RESULTS
47 |  | URANIUM
49 |  | FUEL SERVICES
49 |  | NUKEM

2014 consolidated financial results

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

Under IFRS, we are required to report the results from discontinued operations separately from continuing operations. We have included our operating earnings from BPLP, and the financial impact of the sale, in discontinued operations.

Throughout this document, for comparison purposes, all results for “earnings from continuing operations” and “cash from continuing operations” have been revised to exclude BPLP. The impact of BPLP is shown separately as a discontinued operation.

HIGHLIGHTS DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |  | 2014 |  |  | 2013 |  |  | 2012 |  |  | CHANGE FROM 2013 TO 2014 |
Revenue |  |  | 2,398 |  |  |  | 2,439 |  |  |  | 1,891 |  |  |  | (2 | )%
Gross profit |  |  | 638 |  |  |  | 607 |  |  |  | 540 |  |  |  | 5 | %
Net earnings attributable to equity holders |  |  | 185 |  |  |  | 318 |  |  |  | 253 |  |  |  | (42 | )%
$ per common share (basic) |  |  | 0.47 |  |  |  | 0.81 |  |  |  | 0.64 |  |  |  | (42 | )%
$ per common share (diluted) |  |  | 0.47 |  |  |  | 0.81 |  |  |  | 0.64 |  |  |  | (42 | )%
Adjusted net earnings (non-IFRS, see page 24) |  |  | 412 |  |  |  | 445 |  |  |  | 434 |  |  |  | (7 | )%
$ per common share (adjusted and diluted) |  |  | 1.04 |  |  |  | 1.12 |  |  |  | 1.10 |  |  |  | (7 | )%
Cash provided by (used in) continuing operations (after working capital changes) |  |  | 480 |  |  |  | 524 |  |  |  | 584 |  |  |  | (8 | )%

Net earnings

Our net earnings attributed to equity holders (net earnings) were $185 million ($0.47 per share diluted) compared to $318 million ($0.81 per share diluted) in 2013, mainly due to:

• |  | write-downs totalling $327 million of our investments in Eagle Point mine assets at Rabbit Lake – $126 million, GLE – $184 million, and Goviex – $17 million

• |  | no earnings from BPLP, which we divested in the first quarter of 2014

• |  | the write-off of $41 million of assets under construction as a result of changes made to the scope of a number of projects

• |  | an early termination fee of $18 million incurred as a result of the cancellation of our toll conversion agreement with SFL, which was to expire in 2016

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

• |  | lower earnings in our fuel services segment as a result of a decrease in sales volumes and higher unit cost of sales

• |  | higher losses on foreign exchange derivatives due to the weakening of the Canadian dollar

partially offset by:

• |  | a $127 million gain on the sale of our interest in BPLP

• |  | higher earnings in our uranium segment due to higher average realized prices

• |  | a favourable settlement of $66 million in a dispute regarding a long-term supply contract with a utility customer

• |  | lower exploration costs due to a more focused effort on our core projects in Saskatchewan, with decreases in activity elsewhere, particularly in Australia and at Inkai

• |  | higher tax recoveries resulting from pre-tax losses in Canada, see Income taxes on page 27 for details

THREE-YEAR TREND

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 23

In 2013, our net earnings were $65 million higher than in 2012 primarily due a decrease in impairment charges (the Kintyre project in 2012 - $168 million, the Talvivaara asset in 2013 - $70 million), as well as higher earnings from our fuel services business as a result of an increase in sales volumes and realized prices, lower exploration expenditures, and higher tax recoveries in 2013. This was partially offset by lower earnings from our electricity business and higher losses on foreign exchange derivatives.

Impairment charge on producing assets

During the fourth quarter of 2014, we recognized a $126 million impairment charge related to our Rabbit Lake operation. The impairment was due to the deferral of various projects that were related to planned production over the remaining life of the Eagle Point mine. The amount of the charge was determined as the excess of the carrying value over the recoverable amount. The recoverable amount of the mine was determined to be $29 million. See note 10 to the financial statements.

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, the write-off of assets, NUKEM inventory write-down, loss on exploration properties, gain on interest in BPLP (after tax), and income taxes on adjustments.

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 2014, 2013 and 2012.

($ MILLIONS) |  | 2014 |  |  | 2013 |  |  | 2012 |
Net earnings attributable to equity holders |  |  | 185 |  |  |  | 318 |  |  |  | 253 |
Adjustments |  |  |  |  |  |  |  |  |  |  |  |
Adjustments on derivatives1 |  |  | 47 |  |  |  | 56 |  |  |  | 17 |
Impairment charges |  |  | 327 |  |  |  | 70 |  |  |  | 168 |
Write-off of assets |  |  | 41 |  |  |  | — |  |  |  | — |
NUKEM inventory write-down (recovery) |  |  | (5 | ) |  |  | 14 |  |  |  | — |
Loss on exploration properties |  |  | — |  |  |  | 15 |  |  |  | — |
Gain on interest in BPLP (after tax) |  |  | (127 | ) |  |  | — |  |  |  | — |
Income taxes on adjustments |  |  | (56 | ) |  |  | (28 | ) |  |  | (4 | )
Adjusted net earnings |  |  | 412 |  |  |  | 445 |  |  |  | 434 |

1 | We do not apply hedge accounting for our portfolio of foreign currency forward sales contracts. However, we have adjusted our gains or losses on derivatives to reflect what our earnings would have been had hedge accounting been in place.

24 CAMECO CORPORATION

The following table shows what contributed to the change in adjusted net earnings for 2014.

($ MILLIONS) |
Adjusted net earnings – 2013 |  |  | 445 |
Change in gross profit by segment (we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits) |  |  |  |
Uranium |  | Higher sales volume |  |  | 19 |
|  | Lower realized prices ($US) |  |  | (28 | )
|  | Foreign exchange impact on realized prices |  |  | 115 |
|  | Higher costs |  |  | (55 | )
|  | Hedging benefits |  |  | (67 | )
|  | change – uranium |  |  | (16 | )
Fuel services |  | Lower sales volume |  |  | (6 | )
|  | Higher realized prices ($Cdn) |  |  | 25 |
|  | Higher costs |  |  | (32 | )
|  | Hedging benefits |  |  | (6 | )
|  | change – fuel services |  |  | (19 | )
NUKEM |  | Gross profit, net of pre-tax inventory adjustment |  |  | (17 | )
|  | change – NUKEM |  |  | (17 | )
Other changes |  |  |  |
No earnings from equity investment in BPLP |  |  | (85 | )
Contract termination fee (SFL) |  |  | (18 | )
Lower administration expenditures |  |  | 9 |
Lower exploration expenditures |  |  | 26 |
Debenture redemption premium |  |  | (12 | )
Loss on equity-accounted investments |  |  | (3 | )
Contract settlement |  |  | 66 |
Lower income taxes |  |  | 32 |
Other |  |  | 4 |
Adjusted net earnings – 2014 |  |  | 412 |

THREE-YEAR TREND

Our adjusted net earnings increased from 2012 to 2013, but decreased in 2014.

The 3% increase from 2012 to 2013 resulted from:

• |  | addition of gross profit from NUKEM

• |  | lower exploration costs due to a decrease in activity at our Kintyre project in Australia

• |  | lower income taxes

partially offset by:

• |  | lower earnings from our electricity business due to lower generation, a lower average realized price and higher costs

The 7% decrease from 2013 to 2014 resulted from:

• |  | no earnings from BPLP due to divestiture of our interest in the first quarter of 2014

• |  | an early termination fee of $18 million incurred as a result of the cancellation of our toll conversion agreement with SFL, which was to expire in 2016

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

• |  | lower earnings from our fuel services business as a result of lower sales volumes and higher unit cost of sales

• |  | higher losses on foreign exchange derivatives due to the weakening of the Canadian dollar

partially offset by:

• |  | higher earnings in our uranium segment due to higher average realized prices

• |  | a favourable settlement of $66 million with respect to a dispute regarding a long-term supply contract with a utility customer

• |  | lower exploration costs due to a more focused effort on our core projects in Saskatchewan, with decreases in activity elsewhere, particularly at our Kintyre project in Australia and at Inkai

MANAGEMENT’S DISCUSSION AND ANALYSIS 25

Revenue

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

($ MILLIONS) |  |  |
Revenue – 2013 |  |  | 2,439 |
Uranium |  |  |  |
Higher sales volume |  |  | 58 |
Higher realized prices ($Cdn) |  |  | 87 |
Change in intersegment sales |  |  | (48 | )
Fuel services |  |  |  |
Lower sales volume |  |  | (38 | )
Higher realized prices ($Cdn) |  |  | 25 |
Change in intersegment sales |  |  | 2 |
NUKEM |  |  | (115 | )
Change in intersegment sales |  |  | (24 | )
Other |  |  | 12 |
Revenue – 2014 |  |  | 2,398 |

See 2014 Financial results by segment on page 40 for more detailed discussion.

THREE-YEAR TREND

In 2013, revenue increased by 29% compared to 2012 due to the addition of NUKEM, as well as a higher realized price for uranium.

In 2014, revenue decreased by 2% compared to 2013 due to lower sales revenues in our NUKEM and fuel services segments as we reduced sales volume in response to market conditions. This was partially offset by higher revenues in our uranium business due to higher realized price for uranium resulting from the weakening of the Canadian dollar compared to 2013. The realized foreign exchange rate was 1.10 compared to 1.03 in 2013.

OUTLOOK FOR 2015

We expect consolidated revenue to decrease up to 5% in 2015 due to an expected decrease in uranium and fuel services sales volumes.

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. We expect the quarterly distribution of uranium deliveries to be relatively balanced in 2015. 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.

Average realized prices

|  | 2014 |  |  | 2013 |  |  | 2012 |  |  | CHANGE FROM 2013 TO 2014 |
Uranium1 |  | $US/lb |  |  | 47.53 |  |  |  | 48.35 |  |  |  | 47.72 |  |  |  | (2 | )%
|  | $Cdn/lb |  |  | 52.37 |  |  |  | 49.81 |  |  |  | 47.72 |  |  |  | 5 | %
Fuel services |  | $Cdn/kgU |  |  | 19.70 |  |  |  | 18.12 |  |  |  | 17.75 |  |  |  | 9 | %
NUKEM |  | $Cdn/lb |  |  | 44.90 |  |  |  | 42.26 |  |  |  | — |  |  |  | 6 | %

1 | Average realized foreign exchange rate ($US/$Cdn): 2014 – $1.10, 2013 – $1.03, and 2012 – $1.00

Discontinued operation

On March 27, 2014, we completed the sale of our 31.6% limited partnership interest in BPLP. The aggregate sale price for our interest in BPLP and certain related entities was $450 million. The sale has been accounted for effective January 1, 2014. We realized an after tax gain of $127 million on this divestiture. See note 6 to the financial statements for more information.

26 CAMECO CORPORATION

($ MILLIONS) |  | 2014 |  |  | 2013 |
Share of earnings from BPLP and related entities |  |  | — |  |  |  | 113 |
Tax expense |  |  | — |  |  |  | (28 | )
|  |  |  |  |  |  | 85 |
Gain on disposal of BPLP and related entities |  |  | 145 |  |  |  | — |
Tax expense on disposal |  |  | (18 | ) |  |  | — |
|  |  | 127 |  |  |  | — |
Net earnings from discontinued operations |  |  | 127 |  |  |  | 85 |

Corporate expenses

ADMINISTRATION

($ MILLIONS) |  | 2014 |  |  | 2013 |  |  | CHANGE |
Direct administration |  |  | 163 |  |  |  | 160 |  |  |  | 2 | %
Restructuring |  |  | — |  |  |  | 5 |  |  |  | (100 | )%
Stock-based compensation |  |  | 13 |  |  |  | 20 |  |  |  | (35 | )%
Total administration |  |  | 176 |  |  |  | 185 |  |  |  | (5 | )%

Direct administration costs in 2014 were $3 million higher than in 2013.

We recorded $13 million in stock-based compensation expenses this year under our stock option, restricted share unit, deferred share unit, performance share unit and phantom stock option plans, compared to $20 million in 2013 due to a change in the compensation program. See note 26 to the financial statements.

Outlook for 2015

We expect administration costs (not including stock-based compensation) to be up to 5% higher compared to 2014.

EXPLORATION

Our 2014 exploration activities remained focused on Canada and Australia. As we continued to focus more on our core projects in Saskatchewan, and reduced our activities elsewhere, we decreased our spending from $73 million in 2013 to $47 million in 2014.

Outlook for 2015

We expect exploration expenses to be about 5% to 10% lower than they were in 2014 due to decreased spending at Inkai.

FINANCE COSTS

Finance costs were $77 million compared to $62 million in 2013. The increase from last year largely reflects higher interest on short-term and long-term debt, higher charges with respect to our reclamation provisions and settlement costs of $12 million with respect to the early redemption of our Series C debentures, partially offset by higher foreign exchange gains on intercompany balances. See note 21 to the financial statements.

FINANCE INCOME

Finance income remained stable compared to 2013 at $7 million.

GAINS AND LOSSES ON DERIVATIVES

In 2014, we recorded $121 million in losses on our derivatives compared to losses of $62 million in 2013. The losses reflect the continued weakening of the Canadian dollar compared to the US dollar in 2014. See note 28 to the financial statements.

INCOME TAXES

We recorded an income tax recovery of $175 million in 2014 compared to a recovery of $117 million in 2013. The increase was primarily due to a change in the distribution of earnings between jurisdictions compared to 2013. In 2014, we recorded losses of $841 million in Canada compared to $715 million in 2013, whereas earnings in foreign jurisdictions decreased to $722 million from $830 million. The tax rate in Canada is higher than the average of the rates in the foreign jurisdictions in which our subsidiaries operate. See note 23 to the financial statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS 27

On an adjusted earnings basis, we recognized a tax recovery of $120 million in 2014 compared to a recovery of $61 million in 2013. The increase was related to the items noted above. Our effective tax rate was a recovery of 41% in 2014 compared to 16% in 2013. The table below presents our adjusted earnings and adjusted income tax expenses attributable to Canadian and foreign jurisdictions.

($ MILLIONS) |  | 2014 |  |  | 2013 |
Pre-tax adjusted earnings1 |  |  |  |  |  |  |  |
Canada2 |  |  | (611 | ) |  |  | (466 | )
Foreign2 |  |  | 901 |  |  |  | 849 |
Total pre-tax adjusted earnings |  |  | 290 |  |  |  | 383 |
Adjusted income taxes1 |  |  |  |  |  |  |  |
Canada2 |  |  | (156 | ) |  |  | (94 | )
Foreign |  |  | 36 |  |  |  | 33 |
Adjusted income tax expense (recovery) |  |  | (120 | ) |  |  | (61 | )
Effective tax rate |  |  | (41 | )% |  |  | (16 | )%

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 24).

TRANSFER PRICING DISPUTES

We have been reporting on our transfer pricing dispute with Canada Revenue Agency (CRA) since 2008, when it originated. As well, we recently received a Notice of Proposed Adjustment (NOPA) from the United States Internal Revenue Service (IRS) challenging the transfer pricing used under certain intercompany transactions including uranium purchase and sales arrangements relating to 2009. Below, we discuss the general nature of transfer pricing disputes and, more specifically, the ongoing disputes we have.

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

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

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

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

For the years 2003 to 2009, CRA has shifted CEL’s income (as re-calculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2009, transfer pricing penalties. The IRS is also proposing to allocate a portion of CEL’s income for 2009 to the US, resulting in such income being taxed in multiple jurisdictions. Taxes of approximately $290 million for the 2003 – 2014 years have already been paid in a jurisdiction outside Canada and the US. Bilateral international tax treaties contain provisions that generally seek to prevent taxation of the same income in both countries. As such, in connection with these disputes, we are considering our options including remedies under international tax treaties that would limit double taxation; however, it is unclear whether we will be successful in eliminating all potential double taxation. The expected income adjustments under our tax disputes are represented by the amounts claimed by CRA and IRS and are described below.

28 CAMECO CORPORATION

CRA dispute

Since 2008, CRA has disputed our corporate structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2009 tax returns. We have recorded a cumulative tax provision of $85 million, where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through 2014. We continue to believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

We are confident that we will be successful in our case; however, for the years 2003 through 2009, CRA issued notices of reassessment for approximately $2.8 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $820 million. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229 million, including notices of reassessment recently received for transfer pricing penalties of an aggregate of $156 million for the 2008 and 2009 tax years. We have not yet made any remittance related to the 2008 and 2009 transfer pricing penalties. The Canadian income tax rules include provisions that require larger companies like us to remit 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions and tax loss carryovers, we have paid a net amount of $212 million cash to the Government of Canada, which includes the amounts shown in the table below. As an alternative to paying cash, we are exploring the possibility of providing security in the form of letters of credit to satisfy our requirements under these provisions.

YEAR PAID ($ MILLIONS) |  | CASH TAXES |  |  | INTEREST AND INSTALMENT PENALTIES |  |  | TRANSFER PRICING PENALTIES |  |  | TOTAL |
Prior to 2013 |  |  | — |  |  |  | 13 |  |  |  | — |  |  |  | 13 |
2013 |  |  | 1 |  |  |  | 9 |  |  |  | 36 |  |  |  | 46 |
2014 |  |  | 106 |  |  |  | 47 |  |  |  | — |  |  |  | 153 |
Total |  |  | 107 |  |  |  | 69 |  |  |  | 36 |  |  |  | 212 |

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

Under the Canadian federal and provincial tax rules, the amount required to be paid or secured each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers. The estimated amounts summarized in the table below reflect actual amounts paid and estimated future amounts owing based on the actual and expected reassessments for the years 2003 through 2014. We will update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2014.

$ MILLIONS |  | 2003 - 2014 |  |  | 2015 |  |  | 2016 - 2017 |  |  | 2018 - 2023 |  |  | TOTAL |
50% of cash taxes and transfer pricing penalties paid or owing in the period1 |  |  | 143 |  |  |  | 165 - 190 |  |  |  | 320 - 345 |  |  |  | 80 - 105 |  |  |  | 725 - 750 |

1 | These amounts do not include interest and instalment penalties, which totalled approximately $69 million to December 31, 2014.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to the Government of Canada, including the $212 million already paid to date.

Due to the time it is taking to work through the pre-trial process, we now expect our appeal of the 2003 reassessment to be heard in the Tax Court of Canada in 2016. If this timing is adhered to, we expect to have a Tax Court decision within six to 18 months after the trial is complete.

MANAGEMENT’S DISCUSSION AND ANALYSIS 29

IRS dispute

As noted above, we received a NOPA from the IRS pertaining to the 2009 tax year for certain of our US subsidiaries.

In general, a NOPA is used by the IRS to communicate a proposed adjustment to income and provides the basis upon which the IRS will issue a Revenue Agent’s Report (RAR), which lists the adjustments proposed by the IRS and calculates the tax and any penalties owing based on the proposed adjustments. We currently anticipate receiving a RAR in the first quarter of 2015.

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

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

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

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

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

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

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

Overview of disputes

The table below provides an overview of some of the key points with respect to our CRA and IRS tax disputes.

|  |  |  | CRA |  |  |  | IRS
Basis for dispute |  | • |  | Corporate structure/governance |  | • |  | Income earned on sales of uranium by the US mines to CEL is inadequate
|  | • |  | Transfer pricing methodology used for certain intercompany uranium sale and purchase agreements |  | • |  | Compensation earned by Cameco Inc., one of our US subsidiaries, is inadequate
|  | • |  | Allocates Cameco Europe Ltd. (CEL) income (as adjusted) for 2003 through 2009 to Canada (same income we paid tax on in foreign jurisdictions and includes income that IRS is proposing to tax) |  | • |  | Allocates a portion of CEL’s 2009 income to the US (a portion of the same income we paid tax on in foreign jurisdictions and which the CRA is proposing to tax)
Years under consideration |  | • |  | CRA reassessed 2003 to 2009 |  | • |  | IRS issued Notice of Proposed Adjustment (NOPA) for 2009
|  | • |  | Auditing 2010 to 2012 |  | • |  | Auditing 2010 to 2012
Timing of resolution |  | • |  | Expect our appeal of the 2003 reassessment to be heard in the Tax Court in 2016 |  | • |  | Expect Revenue Agent’s Report (follows NOPA) in Q1 2015
|  | • |  | Expect Tax Court decision six to 18 months after completion of trial |  | • |  | Plan to contest proposed adjustments in an administrative appeal
|  |  |  |  |  | • |  | This dispute is at an early stage, and we cannot yet provide an estimate as to the timeline for resolution

30 CAMECO CORPORATION

|  |  |  | CRA |  |  |  | IRS
Required payments |  | • |  | Expect to remit 50% of cash taxes, interest and penalties as reassessed |  | • |  | No payments required while under administrative appeal
|  | • |  | Paid $212 million in cash to date |  |  |  |
|  | • |  | Exploring possibility of providing security in the form of letters of credit to satisfy required remittances |  |  |  |

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

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

Assumptions

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

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

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

• |  | we will be substantially successful in our dispute with CRA and the cumulative tax provision of $85 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date

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

• |  | we will be substantially successful in our dispute with IRS

Material risks that could cause actual results to differ materially

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

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

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

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

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

• |  | we are unable to effectively eliminate all double taxation

OUTLOOK FOR 2015

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 tax recovery of 60% to 65% in 2015 from our uranium, fuel services and NUKEM segments, as taxable income in Canada is expected to decline. In 2016, the older contractual arrangements under our portfolio of intercompany sale and purchase arrangements largely expire, and we expect our portfolio to be increasingly reflective of the market at the time transactions occur under the contracts. As this transition occurs, we expect our consolidated tax rate to increase from a recovery to an expense, however the rate of change will depend on market conditions at the time new contracts are put in place and when transactions occur under the contracts.

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 sales less US dollar cash expenses and product purchases) 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 49 and 60 months).

MANAGEMENT’S DISCUSSION AND ANALYSIS 31

At December 31, 2014:

• |  | The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.16 (Cdn), up from $1.00 (US) for $1.06 (Cdn) at December 31, 2013. The exchange rate averaged $1.00 (US) for $1.10 (Cdn) over the year.

• |  | We had foreign currency forward contracts of $1.6 billion (US), EUR 5 million and foreign currency options of $100 million (US) at December 31, 2014. The US currency forward contracts had an average exchange rate of $1.00 (US) for $1.12 (Cdn) and US currency option contracts had an average exchange rate range of $1.00 (US) for $1.13 to $1.21 (Cdn).

• |  | The mark-to-market loss on all foreign exchange contracts was $67 million compared to a $27 million loss at December 31, 2013.

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2014, 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, 2014, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2015 net earnings by about $7 million (Cdn), with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact. This sensitivity is based on an exchange rate of $1.00 (US) for $1.00 (Cdn).

Outlook for 2015

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

Our outlook for 2015 reflects the expenditures necessary to help us achieve our strategy. We do not provide an outlook for the items in the table that are marked with a dash.

See 2014 Financial results by segment on page 40 for details.

2015 FINANCIAL OUTLOOK

|  | CONSOLIDATED |  |  | URANIUM1 |  |  | FUEL SERVICES |  |  | NUKEM1 |
Production |  |  | — |  |  |  | 25.3 to 26.3 million lbs |  |  |  | 9 to 10 million kgU |  |  |  | — |
Sales volume1 |  |  | — |  |  |  | 31 to 33 million lbs |  |  |  | Decrease 5% to 10% |  |  |  | 7 to 8 million lbs U3O8 |
Revenue compared to 20142 |  |  | Decrease 0% to 5% |  |  |  | Decrease 5% to 10% | 3 |  |  | Decrease 0% to 5% |  |  |  | Increase 5% to 10% |
Average unit cost of sales (including D&A) |  |  | — |  |  |  | Increase 5% to 10% | 4 |  |  | Increase 5% to 10% |  |  |  | Increase 0% to 5% |
Direct administration costs compared to 20145 |  |  | Increase 0% to 5% |  |  |  | — |  |  |  | — |  |  |  | Decrease 0% to 5% |
Exploration costs compared to 2014 |  |  | — |  |  |  | Decrease 5% to 10% |  |  |  | — |  |  |  | — |
Tax rate |  |  | Recovery of 60% to 65% |  |  |  | — |  |  |  | — |  |  |  | Expense of 30% to 35% |
Capital expenditures |  |  | $370 million |  |  |  | — |  |  |  | — |  |  |  | — |

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

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

3 | Based on a uranium spot price of $37.50 (US) per pound (the Ux spot price as of February 2, 2015), a long-term price indicator of $49.00 (US) per pound (the Ux long-term indicator on January 26, 2015) and an exchange rate of $1.00 (US) for $1.10 (Cdn).

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

5 | Direct administration costs do not include stock-based compensation expenses. See page 27 for more information.

32 CAMECO CORPORATION

REVENUE AND EARNINGS SENSITIVITY ANALYSIS

For 2015, a change of $5 (US) per pound in each of the Ux spot price ($37.50 (US) per pound on February 2, 2015) and the Ux long-term price indicator ($49.00 (US) per pound on January 26, 2015) would change revenue by $93 million and net earnings by $55 million.

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

The table below and graph on the following page are not forecasts of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table and graph. They are designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2014 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on December 31, 2014, and none of the assumptions we list below change.

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

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)

SPOT PRICES ($US/lb U3O8) |  | $20 |  |  | $40 |  |  | $60 |  |  | $80 |  |  | $100 |  |  | $120 |  |  | $140 |
2015 |  |  | 41 |  |  |  | 46 |  |  |  | 55 |  |  |  | 63 |  |  |  | 72 |  |  |  | 80 |  |  |  | 87 |
2016 |  |  | 41 |  |  |  | 47 |  |  |  | 57 |  |  |  | 68 |  |  |  | 78 |  |  |  | 87 |  |  |  | 95 |
2017 |  |  | 41 |  |  |  | 46 |  |  |  | 57 |  |  |  | 67 |  |  |  | 78 |  |  |  | 87 |  |  |  | 94 |
2018 |  |  | 42 |  |  |  | 48 |  |  |  | 58 |  |  |  | 69 |  |  |  | 79 |  |  |  | 87 |  |  |  | 93 |
2019 |  |  | 43 |  |  |  | 49 |  |  |  | 59 |  |  |  | 69 |  |  |  | 78 |  |  |  | 85 |  |  |  | 91 |

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

Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. Those that are fixed at lower prices or have low ceiling prices will yield prices that are lower than current market prices.

Our portfolio is affected by more than just the spot price. We made the following assumptions (which are not forecasts) to create the table:

Sales

• |  | sales volumes on average of 27 million pounds per year, with commitment levels in 2015 through 2018 higher than in 2019

• |  | excludes sales between our uranium, fuel services and NUKEM segments

MANAGEMENT’S DISCUSSION AND ANALYSIS 33

Deliveries

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

• |  | we defer a portion of deliveries under existing contracts for 2015

Annual inflation

• |  | is 2% in the US

Prices

• |  | the average long-term price indicator is the same as the average spot price for the entire year (a simplified approach for this purpose only). Since 1996, the long-term price indicator has averaged 18% higher than the spot price. This differential has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table and graph will be higher.

Liquidity and capital resources

At the end of 2014, we had cash and short-term investments of $567 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 maintaining and prudently expanding our production capacity over the next several years. We have a number of alternatives to fund future capital requirements, including using our current cash balances, drawing on our existing credit facilities, entering new credit facilities, using our operating cash flow, and raising additional capital through debt or equity financings. We are always considering our financing options so we can take advantage of favourable market conditions when they arise. However, we expect our cash balances and operating cash flows will meet our anticipated 2015 capital requirements without the need for significant additional funding.

We have an ongoing dispute with CRA regarding our offshore marketing company structure and related transfer pricing arrangements. See page 27 for more information. Until this dispute is settled, we expect to make remittances for future amounts owing to the Government of Canada for 50% of the cash taxes payable and the related interest and penalties. We have provided an estimate of the amount and timing of the expected cash taxes and transfer pricing penalties paid or owing in the table on page 27.

FINANCIAL CONDITION

|  | 2014 |  |  | 2013 |
Cash position ($ millions) (cash, cash equivalents, short-term investments, less bank overdraft) |  |  | 567 |  |  |  | 188 |
Cash provided by continuing operations ($ millions) (net cash flow generated by our operating activities after changes in working capital) |  |  | 480 |  |  |  | 524 |
Cash provided by operations/net debt (net debt is total consolidated debt, less cash position) |  |  | 52 | % |  |  | 45 | %
Net debt/total capitalization (total capitalization is total long-term debt and equity) |  |  | 13 | % |  |  | 17 | %

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, 2014:

SECURITY |  | DBRS |  | S&P |
Commercial paper |  | R-1 (low) |  |  | A-1 (low)1 |
Senior unsecured debentures |  | A (low) |  |  | BBB+ |
Rating trend / rating outlook |  | Stable |  |  | Negative |

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

34 CAMECO CORPORATION

DBRS provides guidance for the outlook of the assigned rating using the rating trend. The rating trend represents their assessment of the likelihood and direction that the rating could change in the future, should present tendencies continue, or in some cases, if challenges are not overcome.

S&P uses rating outlooks to assess the potential direction of a long-term credit rating over the intermediate term. Their outlook indicates the likelihood that the rating could change in the future.

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) |  | 2014 |  |  | 2013 |
Cash, cash equivalents and short-term investments at beginning of year |  |  | 188 |  |  |  | 799 |
Cash from operations |  |  | 480 |  |  |  | 530 |
Investment activities |  |  |  |  |  |  |  |
Additions to property, plant and equipment and acquisitions |  |  | (480 | ) |  |  | (898 | )
Discontinued operation |  |  | 447 |  |  |  | — |
Other investing activities |  |  | 12 |  |  |  | (6 | )
Financing activities |  |  |  |  |  |  |  |
Change in debt |  |  | 146 |  |  |  | (18 | )
Interest paid |  |  | (78 | ) |  |  | (66 | )
Contributions from non-controlling interest |  |  | 1 |  |  |  | — |
Issue of shares |  |  | 6 |  |  |  | 2 |
Dividends |  |  | (158 | ) |  |  | (158 | )
Exchange rate on changes on foreign currency cash balances |  |  | 3 |  |  |  | 3 |
Cash, cash equivalents and short-term investments, less bank overdraft at end of year |  |  | 567 |  |  |  | 188 |

CASH FROM CONTINUING OPERATIONS

Cash from continuing operations was 8% lower than in 2013 mainly due to higher payments related to our CRA litigation, offset by working capital requirements and higher profits in the uranium business. Not including working capital requirements, our operating cash flows in the year were down $96 million. See note 25 to the financial statements.

INVESTING ACTIVITIES

Cash used in investing includes acquisitions and capital spending.

Acquisitions and divestitures

On January 30, 2014, we signed an agreement with BPC Generation Infrastructure Trust to sell our 31.6% limited partnership interest in BPLP and related entities for $450 million. The effective date for the sale is January 1, 2014. We have realized an after tax gain of $127 million on this divestiture.

Capital spending

We classify 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 35

CAMECO’S SHARE ($ MILLIONS) |  | 2014 PLAN |  |  | 2014 ACTUAL |  |  | 2015 PLAN |
Sustaining capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 25 |  |  |  | 22 |  |  |  | 25 |
Cigar Lake |  |  | 25 |  |  |  | 14 |  |  |  | 15 |
Rabbit Lake |  |  | 45 |  |  |  | 33 |  |  |  | 35 |
US ISR |  |  | 5 |  |  |  | 3 |  |  |  | 5 |
Inkai |  |  | 10 |  |  |  | 9 |  |  |  | 5 |
Fuel services |  |  | 10 |  |  |  | 8 |  |  |  | 15 |
Other |  |  | 15 |  |  |  | 6 |  |  |  | 5 |
Total sustaining capital |  |  | 135 |  |  |  | 95 |  |  |  | 105 |
Capacity replacement capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 55 |  |  |  | 57 |  |  |  | 85 |
Cigar Lake |  |  | 35 |  |  |  | 38 |  |  |  | 35 |
Rabbit Lake |  |  | — |  |  |  | — |  |  |  | — |
US ISR |  |  | 20 |  |  |  | 23 |  |  |  | 20 |
Inkai |  |  | 15 |  |  |  | 10 |  |  |  | 15 |
Total capacity replacement capital |  |  | 125 |  |  |  | 128 |  |  |  | 155 |
Growth capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 60 |  |  |  | 51 |  |  |  | 25 |
Cigar Lake |  |  | 155 |  |  |  | 186 |  |  |  | 70 |
US ISR |  |  | 5 |  |  |  | 2 |  |  |  | — |
Inkai |  |  | 5 |  |  |  | 10 |  |  |  | 5 |
Fuel services |  |  | 5 |  |  |  | 6 |  |  |  | 5 |
Other |  |  | — |  |  |  | 2 |  |  |  | 5 |
Total growth capital |  |  | 230 |  |  |  | 257 |  |  |  | 110 |
Total uranium & fuel services |  |  | 490 | 1 |  |  | 480 |  |  |  | 370 |

1 | Capital spending outlook was updated to $490 million in our third quarter MD&A.

Outlook for investing activities

(CAMECO’S SHARE IN $ MILLIONS) |  | 2016 PLAN |  | 2017 PLAN
Total uranium & fuel services |  | 300-350 |  | 350-400
Sustaining capital |  | 125-140 |  | 155-170
Capacity replacement capital |  | 100-115 |  | 125-140
Growth capital |  | 75-95 |  | 70-90

We expect total capital expenditures for uranium and fuel services to decrease by about 23% in 2015.

Major sustaining, capacity replacement and growth expenditures in 2015 include:

• |  | McArthur River/Key Lake – At McArthur River, the largest projects are the upgrade of the electrical infrastructure, the expansion of freeze capacity and mine development. Other projects include site facility and equipment purchases. At Key Lake, work will be completed on the calciner.

• |  | US in situ recovery (ISR) – wellfield construction represents the largest portion of our expenditures in the US.

• |  | Rabbit Lake – At Eagle Point, the largest component is mine development, along with mine equipment upgrades and purchases. Work on various mill facility and equipment replacements will also continue.

• |  | Cigar Lake – Underground mine development makes up the largest portion of capital at the Cigar Lake site. We are also paying our share of the costs to modify and expand the McClean Lake mill.

We previously expected to spend between $400 million and $450 million in 2015, and between $500 million and $550 million in 2016. We now expect to spend $370 million in 2015 and between $300 million and $350 million in 2016. The change is due to the removal of our fixed production target and the decrease in spending on the related projects. As the market begins to signal new production is needed, we plan to increase our capital expenditures to allow us to be among the first to respond to the growth we see coming.

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 2 and 3. Our actual capital expenditures for future periods may be significantly different.

36 CAMECO CORPORATION

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 ($ MILLIONS) |  | 2015 |  |  | 2016 AND 2017 |  |  | 2018 AND 2019 |  |  | 2020 AND BEYOND |  |  | TOTAL |
Long-term debt |  |  | — |  |  |  | — |  |  |  | 500 |  |  |  | 1,000 |  |  |  | 1,500 |
Interest on long-term debt |  |  | 69 |  |  |  | 139 |  |  |  | 139 |  |  |  | 267 |  |  |  | 614 |
Provision for reclamation |  |  | 19 |  |  |  | 60 |  |  |  | 75 |  |  |  | 720 |  |  |  | 874 |
Provision for waste disposal |  |  | 2 |  |  |  | 9 |  |  |  | 5 |  |  |  | 2 |  |  |  | 18 |
Other liabilities |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 62 |  |  |  | 62 |
Capital commitments |  |  | 99 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 99 |
Total |  |  | 189 |  |  |  | 208 |  |  |  | 719 |  |  |  | 2,051 |  |  |  | 3,167 |

We have contractual capital commitments of approximately $99 million at December 31, 2014. Certain of the contractual commitments may contain cancellation clauses; however, we disclose the commitments based on management’s intent to fulfill the contracts. The majority of the $99 million is expected to be incurred in 2015.

We have unsecured lines of credit of about $2.4 billion, which include the following:

• |  | A $1.25 billion unsecured revolving credit facility that matures November 1, 2018. 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, 2014, there were no amounts outstanding under this facility.

• |  | Approximately $951 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, 2014, we had approximately $942 million outstanding in letters of credit.

In the second quarter of 2014, we issued $500 million in Series G debentures bearing interest at 4.19% per year, maturing on June 24, 2024. On July 16, 2014, we redeemed Series C debentures in aggregate principal amount of $300 million.

In total, considering the early redemption of the Series C debentures, we have $1.5 billion in senior unsecured debentures outstanding:

• |  | $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

• |  | $500 million bearing interest at 4.19% per year, maturing on June 24, 2024

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

The $73 million (US) promissory note we issued to GLE to support future development of its business has been fully drawn and no obligation is outstanding.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 37

Not complying with any of these covenants could result in accelerated payment and termination of our revolving credit facility. At December 31, 2014, we complied with all covenants, and we expect to continue to comply in 2015.

Nukem financing arrangement

NUKEM enters into financing arrangements with third parties where future receivables arising from certain sales contracts are sold to financial institutions in exchange for cash. These arrangements require NUKEM to satisfy its delivery obligations under the sales contracts, which are recognized as deferred sales (see notes 9 and 17 to the financial statements for more information). In some of the arrangements, NUKEM is also required to pledge the underlying inventory as security against these performance obligations. As of December 31, 2014, NUKEM had $64.7 million (US) of inventory pledged as security under financing arrangements, compared with $31.8 million (US) at December 31, 2013.

OFF-BALANCE SHEET ARRANGEMENTS

We had two kinds of off-balance sheet arrangements at the end of 2014:

• |  | purchase commitments

• |  | financial assurances

Purchase commitments

The table below is based on our purchase commitments at December 31, 2014. These commitments include a mix of fixed price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of purchase. We will update this table as required in our MD&A to reflect changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.

DECEMBER 31 ($ MILLIONS) |  | 2015 |  |  | 2016 AND 2017 |  |  | 2018 AND 2019 |  |  | 2020 AND BEYOND |  |  | TOTAL |
Purchase commitments1 |  |  | 733 |  |  |  | 648 |  |  |  | 285 |  |  |  | 502 |  |  |  | 2,168 |

1 | Denominated in US dollars, converted to Canadian dollars as of December 31, 2014 at the rate of $1.16.

At the end of 2014, we had committed to $2.2 billion (Cdn) for the following:

• |  | approximately 35 million pounds of U3O8 equivalent from 2015 to 2028

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

• |  | about 1 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-Western supplier

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

Financial assurances

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. At December 31, 2014 our financial assurances totaled $942 million compared to $849 million at December 31, 2013. The increase is mainly due to increased requirements for decommissioning letters of credit for Rabbit Lake and McArthur River, and exchange rate fluctuations. The increases were partially offset by the sale of BPLP, which eliminated our commitment for financial guarantees on its behalf. These guarantees were estimated at $58 million at the end of 2013.

38 CAMECO CORPORATION

BALANCE SHEET

DECEMBER 31 ($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | 2014 |  |  | 2013 |  |  | 2012 |  |  | CHANGE 2013 TO 2014 |
Inventory |  |  | 902 |  |  |  | 913 |  |  |  | 564 |  |  |  | (1 | )%
Total assets |  |  | 8,473 |  |  |  | 8,039 |  |  |  | 7,431 |  |  |  | 5 | %
Long-term financial liabilities |  |  | 2,448 |  |  |  | 1,915 |  |  |  | 1,903 |  |  |  | 28 | %
Dividends per common share |  |  | 0.40 |  |  |  | 0.40 |  |  |  | 0.40 |  |  |  | — |

Total product inventories decreased by 1% to $902 million this year due to lower levels of inventory for uranium and fuel services, where the quantities sold were higher than the quantities produced and purchased for the year, partially offset by higher inventories in our NUKEM segment. In 2014, total volume of product inventories decreased by 24%; however, the average cost of uranium was higher as the cost of material produced and purchased during the year was higher than the average cost of inventory at the beginning of the year. At December 31, 2014, our average cost for uranium was $32.00 per pound, up from $29.15 per pound at December 31, 2013.

At the end of 2014, our total assets amounted to $8.5 billion, an increase of $0.5 billion compared to 2013 primarily due to higher deferred tax assets and an increase in long term receivables related to our CRA litigation. In 2013, the total asset balance increased by $0.6 billion compared to 2012 primarily due to the acquisition of NUKEM in that year.

The major components of long-term financial liabilities are long-term debt, the provision for reclamation, deferred sales and financial derivatives. In 2014, our balance increased by $0.5 billion due to the early redemption of our Series C debentures and the issuance of the Series G debentures, as well as an increase in deferred sales. In 2013, our balance did not change significantly.

MANAGEMENT’S DISCUSSION AND ANALYSIS 39

2014 financial results by segment

Uranium

HIGHLIGHTS |  | 2014 |  |  | 2013 |  |  | CHANGE |
Production volume (million lbs) |  |  | 23.3 |  |  |  | 23.6 |  |  |  | (1 | )%
Sales volume (million lbs) |  |  | 33.9 | 1 |  |  | 32.8 |  |  |  | 3 | %
Average spot price ($US/lb) |  |  | 33.21 |  |  |  | 38.17 |  |  |  | (13 | )%
Average long-term price ($US/lb) |  |  | 46.46 |  |  |  | 54.13 |  |  |  | (14 | )%
Average realized price |  |  |  |  |  |  |  |  |  |  |  |
($US/lb) |  |  | 47.53 |  |  |  | 48.35 |  |  |  | (2 | )%
($Cdn/lb) |  |  | 52.37 |  |  |  | 49.81 |  |  |  | 5 | %
Average unit cost of sales ($Cdn/lb) (including D&A) |  |  | 34.64 |  |  |  | 33.01 |  |  |  | 5 | %
Revenue ($ millions) |  |  | 1,777 | 1 |  |  | 1,633 |  |  |  | 9 | %
Gross profit ($ millions) |  |  | 602 |  |  |  | 550 |  |  |  | 9 | %
Gross profit (%) |  |  | 34 |  |  |  | 34 |  |  |  | — |

1 | Includes sales of 1.4 million pounds and revenue of $48 million between our uranium, fuel services and NUKEM segments.

Production volumes in 2014 did not vary significantly from 2013. Lower production at McArthur River/Key Lake was offset by higher production at other sites. See Uranium – production overview on page 53 for more information.

Uranium revenues this year were up 9% compared to 2013 due to an increase in sales volumes of 3% and an increase of 5% in the Canadian dollar average realized price. Although the spot and term prices were lower than 2013, our average realized prices remained fairly constant compared to 2013, as lower market-related prices were largely offset by higher US dollar prices under fixed price contracts. The effect of foreign exchange resulted in a higher Canadian dollar average realized price than in the prior year. The realized foreign exchange rate was $1.10 compared to $1.03 in 2013. The spot price for uranium averaged $33.21 (US) per pound in 2014, a decline of 13% compared to the 2013 average price of $38.17 (US) per pound.

Total cost of sales (including D&A) also increased by 9% ($1.18 billion compared to $1.08 billion in 2013) mainly due to slightly higher sales volumes and an increase in the average unit cost of sales resulting from an increase in non-cash costs. Total non-cash costs were $273 million compared to $213 million in 2013 as a result of an increase in the average non-cash unit cost of inventory.

The net effect was a $52 million increase 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) |  | 2014 |  |  | 2013 |  |  | CHANGE |
Produced |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 18.66 |  |  |  | 18.37 |  |  |  | 2 | %
Non-cash cost |  |  | 9.30 |  |  |  | 9.46 |  |  |  | (2 | )%
Total production cost |  |  | 27.96 |  |  |  | 27.83 |  |  |  | — |
Quantity produced (million lbs) |  |  | 23.3 |  |  |  | 23.6 |  |  |  | (1 | )%
Purchased |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 38.17 |  |  |  | 27.95 |  |  |  | 37 | %
Quantity purchased (million lbs) |  |  | 7.1 |  |  |  | 13.2 |  |  |  | (46 | )%
Totals |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs |  |  | 30.34 |  |  |  | 27.87 |  |  |  | 9 | %
Quantities produced and purchased (million lbs) |  |  | 30.4 |  |  |  | 36.8 |  |  |  | (17 | )%

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.

40 CAMECO CORPORATION

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 years ended 2014 and 2013 as reported in our financial statements.

CASH AND TOTAL COST PER POUND RECONCILIATION

($ MILLIONS) |  | 2014 |  |  | 2013 |
Cost of product sold |  |  | 902.8 |  |  |  | 869.1 |
Add / (subtract) |  |  |  |  |  |  |  |
Royalties |  |  | (91.2 | ) |  |  | (90.8 | )
Standby charges |  |  | (24.8 | ) |  |  | (37.4 | )
Other selling costs |  |  | (9.0 | ) |  |  | (1.4 | )
Change in inventories |  |  | (71.9 | ) |  |  | 63.1 |
Cash operating costs (a) |  |  | 705.9 |  |  |  | 802.6 |
Add / (subtract) |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 272.6 |  |  |  | 212.9 |
Change in inventories |  |  | (56.2 | ) |  |  | 10.1 |
Total operating costs (b) |  |  | 922.3 |  |  |  | 1,025.6 |
Uranium produced and purchased (million lbs) (c) |  |  | 30.4 |  |  |  | 36.8 |
Cash costs per pound (a ÷ c) |  |  | 23.22 |  |  |  | 21.81 |
Total costs per pound (b ÷ c) |  |  | 30.34 |  |  |  | 27.87 |

OUTLOOK FOR 2015

We expect to produce 25.3 million to 26.3 million pounds in 2015 and have commitments under long-term contracts to purchase approximately 2 million pounds.

Based on the contracts we have in place and not including sales between our segments, we expect to deliver between 31 million and 33 million pounds of U3O8 in 2015. We expect the unit cost of sales to be 5% to 10% higher than in 2014, primarily due to higher costs for produced material. As Cigar Lake ramps up to full production, the cash cost of material produced from the mine will initially be higher. If we make additional discretionary purchases in 2015 at a cost different than our other sources of supply, then we expect the overall unit cost of sales to be affected.

We expect revenue to be 5% to 10% lower than it was in 2014 as a result of an expected decrease in deliveries, not including sales between our segments, and a lower average realized price.

ROYALTIES

We pay royalties on the sale of all uranium extracted at our mines in the province of Saskatchewan. Two types of royalties are paid:

• |  | Basic royalty: calculated as 5% of gross sales of uranium, less the Saskatchewan resource credit of 0.75%.

• |  | Profit royalty: a 10% royalty is charged on profit up to and including $22.28/kg U3O8 ($10.11/lb) and a 15% royalty is charged on profit in excess of $22.28/kg U3O8. Profit is determined as revenue less certain operating, exploration, reclamation and capital costs. Both exploration and capital costs are deductible at the discretion of the producer.

MANAGEMENT’S DISCUSSION AND ANALYSIS 41

During the period from 2013 to 2015, transitional rules apply whereby only 50% of capital costs are deductible. The remaining 50% is accumulated and deductible beginning in 2016. In addition, the capital allowance related to Cigar Lake under the previous system is grandfathered and deductible in 2016.

As a resource corporation in Saskatchewan, we also pay a corporate resource surcharge of 3.0% of the value of resource sales.

Fuel services

(includes results for UF6, UO2 and fuel fabrication)

HIGHLIGHTS |  | 2014 |  |  | 2013 |  |  | CHANGE |
Production volume (million kgU) |  |  | 11.6 |  |  |  | 14.9 |  |  |  | (22 | )%
Sales volume (million kgU) |  |  | 15.5 | 1 |  |  | 17.6 | 2 |  |  | (12 | )%
Realized price ($Cdn/kgU) |  |  | 19.70 |  |  |  | 18.12 |  |  |  | 9 | %
Average unit cost of sales ($Cdn/kgU) (including D&A) |  |  | 17.24 |  |  |  | 15.16 |  |  |  | 14 | %
Revenue ($ millions) |  |  | 306 | 1 |  |  | 319 | 2 |  |  | (4 | )%
Gross profit ($ millions) |  |  | 38 |  |  |  | 52 |  |  |  | (27 | )%
Gross profit (%) |  |  | 12 |  |  |  | 16 |  |  |  | (25 | )%

1 | Includes sales of 0.5 million kgU and revenue of $4 million between our uranium, fuel services and NUKEM segments.

2 | Includes sales of 0.7 million kgU and revenue of $6 million between our uranium, fuel services and NUKEM segments.

Total revenue decreased by 4% due to a 12% decrease in sales volumes, partially offset by a 9% increase in the realized price.

The total cost of products and services sold (including D&A) remained relatively stable compared to 2013 at $268 million, as a 12% decrease in sales volume was offset by a 14% increase in the average unit cost of sales (including D&A).

The net effect was a $14 million decrease in gross profit.

OUTLOOK FOR 2015

In 2015, we plan to produce 9 million to 10 million kgU, and we expect sales volumes not including intersegment sales to be 5% to 10% lower than in 2014. Overall revenue is expected to decrease by up to 5% as lower sales volumes will be partially offset by an increase in the average realized price. We expect the average unit cost of sales (including D&A) to increase by 5% to 10%; therefore, overall gross profit will decrease as a result.

NUKEM

HIGHLIGHTS |  | 2014 |  |  | 2013 |  |  | CHANGE |
Uranium sales (million lbs) |  |  | 8.1 | 1 |  |  | 8.9 | 2 |  |  | (9 | )%
Average realized price ($Cdn/lb) |  |  | 44.90 |  |  |  | 42.26 |  |  |  | 6 | %
Cost of product sold (including D&A) |  |  | 327 |  |  |  | 445 |  |  |  | (27 | )%
Revenue |  |  | 349 | 1 |  |  | 465 | 2 |  |  | (25 | )%
Gross profit |  |  | 22 |  |  |  | 20 |  |  |  | 10 | %
Net earnings |  |  | (3 | ) |  |  | 7 |  |  |  | (143 | )%
Adjustments on derivatives3 |  |  | 2 |  |  |  | (3 | ) |  |  | 167 | %
NUKEM inventory write-down (reversal) (net of tax) |  |  | (4 | ) |  |  | 10 |  |  |  | (140 | )%
Adjusted net earnings (loss)3 |  |  | (5 | ) |  |  | 14 |  |  |  | (136 | )%

1 | Includes sales of 1.1 million pounds and revenue of $43 million between our uranium, fuel services and NUKEM segments.

2 | Includes sales of 0.6 million pounds and revenue of $23 million between our uranium, fuel services and NUKEM segments.

3 | Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (non-IFRS measure, see page 24).

During 2014, NUKEM delivered 8.1 million pounds of uranium, a decrease of 0.8 million pounds compared to the previous year due to weak market conditions. Revenues from NUKEM amounted to $349 million, 25% lower than in 2013 as a result of lower sales volume and a decline in the realized price amid lower market prices.

Gross profit amounted to $22 million, an increase of $2 million compared to 2013. Although sales volumes decreased, NUKEM’s gross margin increased by 10% compared to 2013 due to generally higher margin sales and a $14 million inventory write-down in 2013. On a percentage basis, gross profits were 6% in 2014 compared to 4% in the prior year.

42 CAMECO CORPORATION

After administration costs, interest and income taxes, adjusted net earnings amounted to a loss of $5 million compared to earnings of $14 million in 2013 (non-IFRS measure, see page 29).

OUTLOOK FOR 2015

For 2015, NUKEM expects to deliver between 7 million and 8 million pounds of uranium, resulting in an increase in revenues not including intersegment sales, of 5% to 10% compared to 2014. NUKEM expects to incur administration costs up to 5% lower than in 2014. The effective income tax rate is expected to remain in the range of 30% to 35%.

MANAGEMENT’S DISCUSSION AND ANALYSIS 43

Fourth quarter financial results

Consolidated results

HIGHLIGHTS |  | THREE MONTHS ENDED DECEMBER 31 |  |  | CHANGE |
($ MILLIONS EXCEPT WHERE INDICATED) |  | 2014 |  |  | 2013 |  |
Revenue |  |  | 889 |  |  |  | 977 |  |  |  | (9 | )%
Gross profit |  |  | 251 |  |  |  | 185 |  |  |  | 36 | %
Net earnings attributable to equity holders |  |  | 73 |  |  |  | 64 |  |  |  | 14 | %
$ per common share (basic) |  |  | 0.18 |  |  |  | 0.16 |  |  |  | 13 | %
$ per common share (diluted) |  |  | 0.18 |  |  |  | 0.16 |  |  |  | 13 | %
Adjusted net earnings (non-IFRS, see page 24) |  |  | 205 |  |  |  | 150 |  |  |  | 37 | %
$ per common share (adjusted and diluted) |  |  | 0.52 |  |  |  | 0.38 |  |  |  | 37 | %
Cash provided by continuing operations (after working capital changes) |  |  | 236 |  |  |  | 163 |  |  |  | 45 | %

NET EARNINGS

In the fourth quarter of 2014, our net earnings were $73 million ($0.18 per share diluted), an increase of $9 million compared to $64 million ($0.16 per share diluted) in 2013, mainly due to:

• |  | higher uranium gross profits resulting from higher average realized prices and lower average unit cost of sales

• |  | a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer

• |  | lower exploration expenditures

• |  | higher income tax recovery

partially offset by:

• |  | the impact of a $126 million write-down of our investments in the Eagle Point mine assets at Rabbit Lake

• |  | the write-off of $41 million of assets under construction as a result of changes made to the scope of a number of projects

• |  | no earnings from BPLP due to divestiture of our interest in the first quarter of 2014

• |  | higher losses on foreign exchange derivatives resulting from the weakening of the Canadian dollar

On an adjusted basis, our earnings this quarter were $205 million ($0.52 per share diluted) compared to $150 million ($0.38 per share diluted) (non-IFRS measure, see below) in the fourth quarter of 2013, mainly due to:

• |  | higher uranium gross profits due to a higher average realized price and lower average unit cost of sales

• |  | a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer

• |  | lower exploration expenditures

partially offset by:

• |  | no earnings from BPLP due to divestiture of our interest in the first quarter of 2014

44 CAMECO CORPORATION

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 24 for more information. The following table reconciles adjusted net earnings with our net earnings.

|  | THREE MONTHS ENDED DECEMBER 31 |
($ MILLIONS) |  | 2014 |  |  | 2013 |
Net earnings attributable to equity holders |  |  | 73 |  |  |  | 64 |
Adjustments |  |  |  |  |  |  |  |
Adjustments on derivatives1 |  |  | 10 |  |  |  | 36 |
NUKEM inventory write-down (recovery) |  |  | (4 | ) |  |  | (3 | )
Impairment charges |  |  | 131 |  |  |  | 70 |
Write-off of assets |  |  | 41 |  |  |  | — |
Income taxes on adjustments |  |  | (46 | ) |  |  | (17 | )
Adjusted net earnings |  |  | 205 |  |  |  | 150 |

1 | We do not apply hedge accounting for our portfolio of foreign currency forward sales contracts. However, we have adjusted our gains or losses on derivatives to reflect what our earnings would have been had hedge accounting been in place.

ADMINISTRATION

Direct administration costs were $51 million in the quarter, $6 million higher than the same period last year due to the timing of expenditures. Stock-based compensation expenses were $3 million lower than the fourth quarter of 2013 due to a change in the compensation program. See note 26 to the financial statements.

|  | THREE MONTHS ENDED DECEMBER 31 |  |  | CHANGE |
($ MILLIONS) |  | 2014 |  |  | 2013 |  |
Direct administration |  |  | 51 |  |  |  | 45 |  |  |  | 13 | %
Stock-based compensation |  |  | 3 |  |  |  | 6 |  |  |  | (50 | )%
Total administration |  |  | 54 |  |  |  | 51 |  |  |  | 6 | %

QUARTERLY TRENDS

HIGHLIGHTS |  | 2014 |  |  | 2013 |
($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |  |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |
Revenue |  |  | 889 |  |  |  | 587 |  |  |  | 502 |  |  |  | 419 |  |  |  | 977 |  |  |  | 597 |  |  |  | 421 |  |  |  | 444 |
Net earnings (losses) attributable to equity holders |  |  | 73 |  |  |  | (146 | ) |  |  | 127 |  |  |  | 131 |  |  |  | 64 |  |  |  | 211 |  |  |  | 34 |  |  |  | 9 |
$ per common share (basic) |  |  | 0.18 |  |  |  | (0.37 | ) |  |  | 0.32 |  |  |  | 0.33 |  |  |  | 0.16 |  |  |  | 0.53 |  |  |  | 0.09 |  |  |  | 0.02 |
$ per common share (diluted) |  |  | 0.18 |  |  |  | (0.37 | ) |  |  | 0.32 |  |  |  | 0.33 |  |  |  | 0.16 |  |  |  | 0.53 |  |  |  | 0.09 |  |  |  | 0.02 |
Adjusted net earnings (non-IFRS, see page 24) |  |  | 205 |  |  |  | 93 |  |  |  | 79 |  |  |  | 36 |  |  |  | 150 |  |  |  | 208 |  |  |  | 61 |  |  |  | 27 |
$ per common share (adjusted and diluted) |  |  | 0.52 |  |  |  | 0.23 |  |  |  | 0.20 |  |  |  | 0.09 |  |  |  | 0.38 |  |  |  | 0.53 |  |  |  | 0.15 |  |  |  | 0.07 |
Earnings (losses) from continuing operations |  |  | 72 |  |  |  | (146 | ) |  |  | 127 |  |  |  | 4 |  |  |  | 28 |  |  |  | 163 |  |  |  | 33 |  |  |  | 8 |
$ per common share (basic) |  |  | 0.18 |  |  |  | (0.37 | ) |  |  | 0.32 |  |  |  | 0.01 |  |  |  | 0.07 |  |  |  | 0.41 |  |  |  | 0.08 |  |  |  | 0.02 |
$ per common share (diluted) |  |  | 0.18 |  |  |  | (0.37 | ) |  |  | 0.32 |  |  |  | 0.01 |  |  |  | 0.07 |  |  |  | 0.41 |  |  |  | 0.08 |  |  |  | 0.02 |
Cash provided by (used in) continuing operations (after working capital changes) |  |  | 236 |  |  |  | 263 |  |  |  | (25 | ) |  |  | 7 |  |  |  | 163 |  |  |  | 154 |  |  |  | (33 | ) |  |  | 241 |

Key things to note:

• |  | Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 68% of consolidated revenues in the fourth quarter of 2014 and 65% of consolidated revenues in the fourth quarter of 2013.

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

• |  | Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our results from period to period (see page 24 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 45

DISCONTINUED OPERATION

On March 27, 2014, we completed the sale of our 31.6% limited partnership interest in BPLP.

|  | THREE MONTHS ENDED DECEMBER 31 |
($ MILLIONS) |  | 2014 |  |  | 2013 |
Share of earnings from BPLP and related entities |  |  | — |  |  |  | 48 |
Tax expense |  |  | — |  |  |  | (12 | )
Net earnings from discontinued operations |  |  | — |  |  |  | 36 |

46 CAMECO CORPORATION

Fourth quarter results by segment

Uranium

|  | THREE MONTHS ENDED DECEMBER 31 |  |  | CHANGE |
HIGHLIGHTS |  | 2014 |  |  | 2013 |  |
Production volume (million lbs) |  |  | 8.2 |  |  |  | 7.5 |  |  |  | 9 | %
Sales volume (million lbs) |  |  | 10.7 | 1 |  |  | 12.7 |  |  |  | (16 | )%
Average spot price ($US/lb) |  |  | 37.13 |  |  |  | 35.03 |  |  |  | 6 | %
Average long-term price ($US/lb) |  |  | 48.00 |  |  |  | 50.00 |  |  |  | (4 | )%
Average realized price |  |  |  |  |  |  |  |  |  |  |  |
($US/lb) |  |  | 50.57 |  |  |  | 47.76 |  |  |  | 6 | %
($Cdn/lb) |  |  | 56.78 |  |  |  | 49.80 |  |  |  | 14 | %
Average unit cost of sales ($Cdn/lb) (including D&A) |  |  | 34.27 |  |  |  | 37.94 |  |  |  | (10 | )%
Revenue ($ millions) |  |  | 606 | 1 |  |  | 631 |  |  |  | (4 | )%
Gross profit ($ millions) |  |  | 240 |  |  |  | 150 |  |  |  | 60 | %
Gross profit (%) |  |  | 40 |  |  |  | 24 |  |  |  | 67 | %

1 | Includes sales of 0.4 million pounds and revenue of $15 million between our uranium, fuel services and NUKEM segments.

Production volumes this quarter were 9% higher compared to the fourth quarter of 2013, mainly as a result of higher production at McArthur River/Key Lake, in addition to the first production from Cigar Lake/McClean Lake. See Our operations and projects starting on page 50 for more information.

Uranium revenues were down 4% due to a 16% decrease in sales volumes, which represents normal quarterly variance in our delivery schedule, offset by a 14% increase in average realized price.

The average realized price increased by 14% compared to 2013 due to higher US dollar prices under fixed price contracts, and the effect of foreign exchange. In the fourth quarter of 2014, our realized foreign exchange rate was $1.12 compared to $1.04 in the prior year.

Total cost of sales (including D&A) decreased by 24% ($366 million compared to $481 million in 2013). This was the result of a 10% decrease in the average unit cost of sales and a 16% decrease in sales volumes.

The unit cost of sales decreased due to a decrease in the cash costs of produced material in the fourth quarter compared to the same period in 2013, as a result of increased production and timing of royalties. In addition, standby charges for the McClean Lake mill ceased in the fourth quarter, as production from Cigar Lake commenced.

The net effect was a $90 million increase in gross profit for the quarter.

MANAGEMENT’S DISCUSSION AND ANALYSIS 47

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

|  | THREE MONTHS ENDED DECEMBER 31 |  |  | CHANGE |
($/LB) |  | 2014 |  |  | 2013 |  |
Produced |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 14.19 |  |  |  | 15.61 |  |  |  | (9 | )%
Non-cash cost |  |  | 7.15 |  |  |  | 9.42 |  |  |  | (24 | )%
Total production cost |  |  | 21.34 |  |  |  | 25.03 |  |  |  | (15 | )%
Quantity produced (million lbs) |  |  | 8.2 |  |  |  | 7.5 |  |  |  | 9 | %
Purchased |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 39.03 |  |  |  | 37.26 |  |  |  | 5 | %
Quantity purchased (million lbs) |  |  | 3.7 |  |  |  | 4.4 |  |  |  | (16 | )%
Totals |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs |  |  | 26.84 |  |  |  | 29.55 |  |  |  | (9 | )%
Quantities produced and purchased (million lbs) |  |  | 11.9 |  |  |  | 11.9 |  |  |  | — |

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 2014 and 2013.

CASH AND TOTAL COST PER POUND RECONCILIATION

|  | THREE MONTHS ENDED DECEMBER 31 |
($ MILLIONS) |  | 2014 |  |  | 2013 |
Cost of product sold |  |  | 269.0 |  |  |  | 359.8 |
Add / (subtract) |  |  |  |  |  |  |  |
Royalties |  |  | (34.5 | ) |  |  | (52.5 | )
Standby charges |  |  | — |  |  |  | (11.1 | )
Other selling costs |  |  | (2.3 | ) |  |  | (4.8 | )
Change in inventories |  |  | 28.5 |  |  |  | (10.3 | )
Cash operating costs (a) |  |  | 260.7 |  |  |  | 281.1 |
Add / (subtract) |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 96.7 |  |  |  | 121.2 |
Change in inventories |  |  | (38.0 | ) |  |  | (50.7 | )
Total operating costs (b) |  |  | 319.4 |  |  |  | 351.6 |
Uranium produced & purchased (million lbs) (c) |  |  | 11.9 |  |  |  | 11.9 |
Cash costs ($/lb) (a ÷ c) |  |  | 21.91 |  |  |  | 23.62 |
Total costs ($/lb) (b ÷ c) |  |  | 26.84 |  |  |  | 29.55 |

48 CAMECO CORPORATION

Fuel services

(includes results for UF6, UO2 and fuel fabrication)

|  | THREE MONTHS ENDED DECEMBER 31 |  |  | CHANGE |
HIGHLIGHTS |  | 2014 |  |  | 2013 |  |
Production volume (million kgU) |  |  | 2.7 |  |  |  | 2.7 |  |  |  | — |
Sales volume (million kgU) |  |  | 7.4 | 1 |  |  | 6.5 |  |  |  | 14 | %
Average realized price ($Cdn/kgU) |  |  | 16.92 |  |  |  | 17.24 |  |  |  | (2 | )%
Average unit cost of sales ($Cdn/kgU) (including D&A) |  |  | 14.78 |  |  |  | 14.42 |  |  |  | 2 | %
Revenue ($ millions) |  |  | 125 | 1 |  |  | 112 |  |  |  | 12 | %
Gross profit ($ millions) |  |  | 16 |  |  |  | 18 |  |  |  | (11 | )%
Gross profit (%) |  |  | 13 |  |  |  | 16 |  |  |  | (19 | )%

1 | Includes sales of 0.5 million kgU and revenue of $4 million between our uranium, fuel services and NUKEM segments.

Total revenue increased by 12% due to a 14% increase in sales volumes, partially offset by a 2% decrease in average realized price.

The total cost of sales (including D&A) increased by 17% ($109 million compared to $93 million in the fourth quarter of 2013) mainly due to a 14% increase in sales volumes and a 2% increase in the average unit cost of sales.

The net effect was a $2 million decrease in gross profit.

NUKEM

|  | THREE MONTHS ENDED DECEMBER 31 |  |  | CHANGE |
HIGHLIGHTS |  | 2014 |  |  | 2013 |  |
Uranium sales (million lbs) |  |  | 3.4 | 1 |  |  | 3.3 |  |  |  | 3 | %
Average realized price ($Cdn/lb) |  |  | 52.12 |  |  |  | 41.84 |  |  |  | 25 | %
Cost of product sold (including D&A) |  |  | 156 |  |  |  | 169 |  |  |  | (8 | )%
Revenue |  |  | 159 | 1 |  |  | 188 |  |  |  | (15 | )%
Gross profit |  |  | 3 |  |  |  | 19 |  |  |  | (84 | )%
Net earnings |  |  | (6 | ) |  |  | 13 |  |  |  | (146 | )%
Adjustments on derivatives2 |  |  | — |  |  |  | (1 | ) |  |  | 100 | %
NUKEM inventory write-down (reversal) (net of tax) |  |  | (2 | ) |  |  | (1 | ) |  |  | (100 | )%
Adjusted net earnings (loss)2 |  |  | (8 | ) |  |  | 11 |  |  |  | (173 | )%

1 | Includes sales of 1.1 million pounds and revenue of $43 million between our uranium, fuel services and NUKEM segments.

2 | Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (non-IFRS measure, see page 24).

During the three months ended December 31, 2014, NUKEM delivered 3.4 million pounds of uranium, an increase of 0.1 million pounds compared to 2013 due to timing of customer requirements. NUKEM revenues amounted to $159 million compared to $188 million in 2013 due to a decline in the uranium spot price relative to the previous year.

The unit cost of uranium sold was lower in 2014 as a result of the decline in the spot price.

The net effect was a $16 million decrease in gross profit. On a percentage basis, gross profits were 2% in the fourth quarter of 2014 compared to 10% in the same period in 2013.

Administration costs were higher in the fourth quarter due to the timing of expenditures. In addition, the sale of inventory on hand at the time of the acquisition of NUKEM resulted in an allocation of the historic purchase price to the sale of uranium in the quarter. This resulted in an adjusted net loss for the fourth quarter of 2014 of $8 million, compared to earnings of $11 million (non-IFRS measure, see page 24) in 2013.

MANAGEMENT’S DISCUSSION AND ANALYSIS 49

Our operations and 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.

53 |  | URANIUM – PRODUCTION OVERVIEW
53 |  | PRODUCTION OUTLOOK
54 |  | URANIUM – OPERATING PROPERTIES
54 |  | MCARTHUR RIVER MINE / KEY LAKE MILL
59 |  | CIGAR LAKE
64 |  | INKAI
67 |  | RABBIT LAKE
69 |  | SMITH RANCH-HIGHLAND
70 |  | CROW BUTTE
71 |  | URANIUM – PROJECTS UNDER EVALUATION
71 |  | MILLENNIUM
71 |  | YEELIRRIE
72 |  | KINTYRE
73 |  | URANIUM – EXPLORATION AND CORPORATE DEVELOPMENT
75 |  | FUEL SERVICES
75 |  | BLIND RIVER REFINERY
76 |  | PORT HOPE CONVERSION SERVICES
76 |  | CAMECO FUEL MANUFACTURING INC. (CFM)
78 |  | NUKEM GMBH

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. Our risk policy and process involves a broad, systematic approach to identifying, assessing, reporting and managing the significant risks we face in our business and operations. The policy establishes clear accountabilities for enterprise risk management. We use a common risk matrix throughout the company and consider any risk that has the potential to significantly affect our ability to achieve our corporate objectives or strategic plan as an enterprise risk. However, there is no assurance we will be successful in preventing the harm any of these risks and hazards could cause. We recommend you read our most recent management proxy circular for more information about our risk oversight.

Below we list the regulatory, environmental and operational risks that generally apply to all of our operations 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.

| • |  | 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 Saskatchewan operations and projects under evaluation.

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 and fuel services 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 conceptual decommissioning plans on a regular basis. As the site approaches or goes into decommissioning, regulators review the detailed decommissioning plans. This can result in further regulatory process, as well as additional requirements, costs and financial assurances.

MANAGEMENT’S DISCUSSION AND ANALYSIS 51

At the end of 2014, our estimate of total decommissioning and reclamation costs was $874 million. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $828 million at the end of 2014 (the present value of the $874 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 provide financial assurances for decommissioning and reclamation such as letters of credit to regulatory authorities, as required. We had a total of $911 million in letters of credit supporting our reclamation liabilities at the end of 2014. 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 2014, we invested:

• |  | $78 million in environmental protection, monitoring and assessment programs, or 26% less than 2013 as a result of large capital projects nearing completion

• |  | $24 million in health and safety programs, or 22% more than 2013

Spending on both environmental and safety programs is expected to increase slightly in 2015, as a result of specific capital projects that are expected to begin during the year.

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.

52 CAMECO CORPORATION

Uranium – production overview

Production in our uranium segment this quarter was 0.7 million pounds higher compared to the fourth quarter of 2013. Production for the year was 0.3 million pounds lower than in 2013. See Uranium operating properties starting on page 54 for more information.

Uranium production

CAMECO’S SHARE |  | THREE MONTHS ENDED DECEMBER 31 |  |  | YEAR ENDED DECEMBER 31 |  |  |  |  |
(MILLION LBS) |  | 2014 |  |  | 2013 |  |  | 2014 |  |  | 2013 |  |  | 2014 PLAN1 |  | 2015 PLAN
McArthur River/Key Lake |  |  | 4.4 |  |  |  | 4.0 |  |  |  | 13.3 |  |  |  | 14.1 |  |  | 12.8 |  | 13.7
Rabbit Lake |  |  | 2.1 |  |  |  | 2.1 |  |  |  | 4.2 |  |  |  | 4.1 |  |  | 4.1 |  | 3.9
Smith Ranch-Highland |  |  | 0.6 |  |  |  | 0.5 |  |  |  | 2.1 |  |  |  | 1.7 |  |  | 2.0 |  | 1.4
Crow Butte |  |  | 0.2 |  |  |  | 0.2 |  |  |  | 0.6 |  |  |  | 0.7 |  |  | 0.6 |  | 0.3
Inkai |  |  | 0.7 |  |  |  | 0.7 |  |  |  | 2.9 |  |  |  | 3.0 |  |  | 3.0 |  | 3.0
Cigar Lake |  |  | 0.2 |  |  |  | — |  |  |  | 0.2 |  |  |  | — |  |  | 0.1 - 0.3 |  | 3.0 – 4.0
Total |  |  | 8.2 |  |  |  | 7.5 |  |  |  | 23.3 |  |  |  | 23.6 |  |  | 22.6 – 22.8 |  | 25.3 – 26.3

1 | We updated our initial 2014 plan for McArthur River/Key Lake (to 12.8 from 13.1 million pounds) and Cigar Lake (to between 0.1 and 0.3 from between 1.0 and 1.5 million pounds) in our Q3 MD&A.

Production Outlook

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

We plan to:

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

• |  | ensure continued reliable, low-cost production at Inkai

• |  | successfully ramp up production at Cigar Lake

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

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 53

Uranium – operating properties

McArthur River mine / Key Lake mill

|  | 2014 Production (our share) |  | Proportion of 2014 U production
| 13.3M lbs |
| 2015 Production Outlook (our share) |
| 13.7M lbs |
| Estimated Reserves (our share) |
| 241.0M lbs |
| Estimated Mine Life |
| 2033 |

McArthur River is the world’s largest, high-grade uranium mine, and Key Lake is the world’s largest uranium mill.

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 of both the mine and mill.

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) |  | 241.0 million pounds (proven and probable), average grade U3O8: 14.87%
Estimated resources (our share) |  | 7.4 million pounds (measured and indicated), average grade U3O8: 4.24% 39.9 million pounds (inferred), average grade U3O8: 7.38%
Mining methods |  | Primary: raiseboring Secondary: blasthole stoping, boxhole boring
Licensed capacity |  | Mine: 21.0 million pounds per year Mill: 25.0 million pounds per year
Licence term |  | Through October, 2023
Total production: 2000 to 2014 (100% basis) 1983 to 2002 |  | 269.7 million pounds (McArthur River/Key Lake) 209.8 million pounds (Key Lake)
2014 production (our share) |  | 13.3 million pounds (19.1 million pounds on 100% basis)
2015 production outlook (our share) |  | 13.7 million pounds (19.6 million pounds on 100% basis)
Estimated decommissioning cost (100% basis) |  | $48 million – McArthur River $218 million – Key Lake

BACKGROUND

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 isolated six mining areas with freezewalls.

54 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

McArthur River currently has six areas with delineated mineral reserves and delineated mineral resources (zones 1 to 4, zone 4 south and zone B) and two additional areas with delineated mineral resources (zone A, McArthur north). We are currently mining zone 2 and 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 freezewall around the ore. As the freezewall is expanded, the inner connecting freezewalls 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 and began mining zone 4 north in the fourth quarter of 2014.

The CNSC has granted approval for the use of two secondary extraction methods: blasthole stoping and boxhole boring.

We have used the approved mining methods to successfully extract about 272 million pounds (100% basis) since we began mining in 1999. Raisebore mining is scheduled to remain the primary extraction method over the life of mine.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 55

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 allow for more economic recovery of ore on the periphery of the orebody, as well as smaller, lower grade areas, and we continue to study opportunities to increase the use of blasthole stoping, which would improve cost efficiency and productivity.

Initial processing

We carry out initial processing of the extracted ore at McArthur River:

• |  | the underground circuit grinds the ore and mixes it with water to form a slurry

• |  | the slurry is pumped 680 metres to the surface and stored in one of four ore slurry holding tanks

• |  | it is blended and thickened, removing excess water

• |  | the final slurry, at an average grade of 15% U3O8, is pumped into transport truck containers and shipped to Key Lake mill on an 80 kilometre all-weather road

Water from this process, including water from underground operations, is treated on the surface. Any excess treated water is released into the environment.

2014 UPDATE

Production

Production from McArthur River/Key Lake was 19.1 million pounds; our share was 13.3 million pounds. This was 4% higher than our forecast for the year as a result of a record month of production at Key Lake in December. However, annual production was 6% lower than in 2013 due to a labour disruption that resulted in an unplanned shutdown of the operations for approximately 18 days during the third quarter of 2014.

Licensing and production capacity

In 2014, the CNSC approved the EA for the Key Lake extension, a project which involves increasing our tailings capacity and Key Lake’s nominal annual production rate. We also received approval to increase the production limit at McArthur River. The licence conditions handbooks for these operations now allow:

• |  | the Key Lake mill to produce up to 25 million pounds (100% basis) per year

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

With the approved EA, and once the Key Lake extension project is complete, mill production can be increased to closely follow production from the McArthur River mine.

McArthur River production expansion

We have been working to increase our annual production rate at McArthur River to 22 million pounds (100% basis). Since, in 2014, we received approval to produce up to 21 million pounds (100% basis) per year, we decided to file an application with the CNSC to increase licensed annual production up to 25 million pounds (100% basis) to allow flexibility to match the approved Key Lake mill capacity. The application was filed in January 2015.

56 CAMECO CORPORATION

In order to sustain or increase production, we must continue to successfully transition into new mine areas through mine development and investment in support infrastructure. We plan to:

• |  | obtain all the necessary regulatory approvals

• |  | expand the freeze plant and electrical distribution systems

• |  | optimize the mine ventilation system

• |  | improve our dewatering system and expand our water treatment capacity as required to mitigate capacity losses should mine development increase background water volumes

• |  | expand the concrete distribution systems and batch plant capacity

New mining areas

New mining zones and increased mine production require increased ventilation and freeze capacity. In 2014, we continued to upgrade our electrical infrastructure on surface as part of our plan to address these future needs.

Underground, we began mining in zone 4 north during the fourth quarter of 2014.

Key Lake extension project and mill revitalization

The Key Lake mill began operating in 1983 and we continue to upgrade circuits with new technology to simplify operations and improve environmental performance. As part of the upgrades, we continued to construct a new calciner circuit, and expect to begin operating with the new calciner in 2015.

The revitalization plan is expected to allow the mill to increase its annual uranium production capability to closely follow annual production rates from the McArthur River mine.

Tailings capacity

This year, the CNSC approved the Key Lake extension EA, allowing us to deposit tailings to a higher level in the Deilmann tailing management facility. We now expect to have sufficient 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.

Labour relations

The mine and mill experienced a labour disruption that resulted in an unplanned shutdown of the operations for approximately 18 days during the third quarter of 2014. On October 6, 2014, unionized employees at McArthur River and Key Lake accepted a new four-year contract that includes a 12% wage increase over the term of the agreement. The previous contract expired on December 31, 2013.

Exploration

In 2014, we completed the planned development advance of the underground exploration drifts and underground delineation drilling.

PLANNING FOR THE FUTURE

Production

We plan to produce 19.6 million pounds in 2015; our share is 13.7 million pounds.

Mill revitalization

In 2015, we expect to complete installation and commissioning of the new calciner.

Exploration

In 2015, 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 zone B, and from surface to identify additional mineral resources in the deposit.

MANAGEMENT’S DISCUSSION AND ANALYSIS 57

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, and regulatory approvals. Operational experience gained since the start of production has resulted in a significant reduction in risk.

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.

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.

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.

We also manage the risks listed on pages 51 to 52.

58 CAMECO CORPORATION

Uranium – operating properties

Cigar Lake

|  | 2014 Production (our share) |  | Proportion of 2014 U production
| 170,000 lbs |
| 2015 Production Outlook (our share) |
| 3.0 – 4.0M lbs |
| Estimated Reserves (our share) |
| 117.5M lbs |
| Estimated Mine Life |
| 2028 |

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 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) |  | 117.5 million pounds (proven and probable), average grade U3O8: 17.84%
Estimated resources (our share) |  | 2.3 million pounds (measured and indicated), average grade U3O8: 8.84% 52.5 million pounds (inferred), average grade U3O8: 16.22%
Mining methods |  | Jet boring
Planned capacity |  | 18.0 million pounds per year (our share 9.0 million pounds per year)
Licence term |  | Through June, 2021
Total production (our share) |  | 0.2 million pounds
2014 production (our share) |  | 0.2 million pounds (0.4 million pounds on 100% basis)
2015 production outlook (our share) |  | 3.0 – 4.0 million pounds (6.0 – 8.0 million pounds on 100% basis)
Estimated decommissioning cost (100% basis ) |  | $49 million

BACKGROUND

Development

We began developing the Cigar Lake underground mine in 2005, but development was delayed due to water inflows. In 2014, we started producing from the mine and processing of the ore began at AREVA’s McClean Lake mill. In October, 2014, the mill produced the first uranium concentrate from ore mined at the Cigar Lake operation.

Mining method and techniques

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 59

We are using a hybrid freezing approach with a combination of underground and surface freezing, and are continuing to advance our surface freeze program to support future production. Through 2014, we continued to drill freezeholes from surface, expand the surface freezing infrastructure and put the new freezeholes into operation. To manage our risks and meet our production schedule, the area being mined must meet specific ground freezing requirements 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. 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 (JBS) process

60 CAMECO CORPORATION

We have divided the orebody into production panels, and will have one jet boring machine operating in a panel; at least three production panels need to be frozen at one time to achieve the full production rate of 18 million pounds per year by 2018. In order to achieve our 2015 production target and continue ramping up the operation, three jet boring machines are required; all three are now on site. Later in the mine plan, we may require a fourth jet boring machine to sustain annual production of 18 million pounds.

Milling

All of Cigar Lake’s ore slurry will be processed at the McClean Lake mill, operated by AREVA. The McClean Lake mill is undergoing modifications and expansion in order to:

• |  | operate at Cigar Lake’s targeted annual production level of 18 million pounds U3O8

• |  | process and package all of Cigar Lake’s current mineral reserves

The Cigar Lake joint venture is paying for the capital costs for the modification and expansion.

2014 UPDATE

Production

Total production from Cigar Lake was 340,000 pounds; our share was 170,000 pounds.

During the year, we:

• |  | brought the Cigar Lake mine into production

• |  | began processing the ore at AREVA’s McClean Lake mill, which, in the fourth quarter, produced the first uranium concentrate from the Cigar Lake operation

• |  | continued freezing the ground from surface to ensure frozen ore is available for future production years

Costs (all showing our share)

At the time of first production in March, 2014, we had:

• |  | invested about $1.2 billion for our share of the construction costs to develop Cigar Lake

• |  | expensed about $91 million in remediation expenses

• |  | expensed about $111 million in standby costs

After production began in March, and to December 31, 2014, we spent:

• |  | $83 million on the McClean Lake mill

• |  | $16 million on standby costs, which were expensed, and ceased August 31, 2014

Additional expenditures of about $60 to $70 million will be required at McClean Lake mill in 2015 in order to continue ramping up to full production.

In addition, during the year, we spent:

• |  | $57 million on operating costs

• |  | $21 million to complete various capital projects at site

• |  | $39 million on underground development

Some of the costs were capitalized, while others were charged to inventory, depending on the nature of the activity.

We will continue to capitalize some of the costs at Cigar Lake until such time that commercial production is reached. Commercial production is reached when management determines that the mine is able to produce at a consistent or sustainably increasing level.

PLANNING FOR THE FUTURE

Production

In 2015, we expect to:

• |  | begin commercial production

• |  | have three jet boring machines operating underground

• |  | continue ramping up towards the planned full production rate of 18 million pounds (100% basis) by 2018

MANAGEMENT’S DISCUSSION AND ANALYSIS 61

Rampup schedule

We expect Cigar Lake to produce between 6 million and 8 million packaged pounds in 2015; our share is 3 million to 4 million pounds. Based on our operating experience and productivity during rampup, we will adjust our annual production plans as necessary to allow us to reach our full annual production rate of 18 million pounds (100% basis) by 2018.

Caution regarding forward-looking information

Our expectations and plans regarding Cigar Lake, including our expected share of 2015 production, achievement of the full annual production rate of 18 million pounds by 2018, and capital costs, are forward-looking information. They are based on the assumptions and subject to the material risks discussed on pages 2 and 3, and specifically on these assumptions and risks:

Assumptions

| • |  | our Cigar Lake development, mining and production plans succeed

| • |  | 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 bulk ground freezing program progresses fast enough to deliver sufficient frozen ore to meet production targets

| • |  | our expectation that the jet boring mining method will be successful and that we will be able to solve technical challenges as they arise in a timely manner

| • |  | our expectation that the third jet boring machine will be operational on schedule in 2015 and operate as expected

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

| • |  | modification and expansion of the McClean Lake mill is completed as planned and the mill is able to process Cigar Lake ore as expected, AREVA will be able to solve technical challenges as they arise in a timely manner, and sufficient tailings facility capacity is available

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

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

| • |  | 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 freezing the deposit to meet production targets, the third jet boring machine does not go into operation on schedule in 2015 or operate as expected, technical difficulties with the McClean Lake mill modifications or expansion or milling Cigar Lake ore

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.

Jet boring mining method

Although we have successfully demonstrated the jet boring mining method in trials and initial mining to date, this method has not been proven at full production and we continue with commissioning work to determine if the method is capable of achieving the designed annual production rate. Mining has been completed on a limited number of cavities that may not be representative of the deposit as a whole. As we ramp up production, there may be some technical challenges, which could affect our production plans including, but not limited to, variable or unanticipated ground conditions, ground movement and cave-ins, water inflows and variable dilution, recovery values and mining productivity. There is a risk that 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. 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.

62 CAMECO CORPORATION

We brought the mine into production using one jet boring machine. To reach our 2015 production target and the full production rate of 18 million pounds per year by 2018 (100% basis), our mine plan requires three jet boring machines. We currently have all three machines on site, with two in operation underground and the third expected to be in operation underground in 2015. We are assessing whether a fourth jet boring machine will be required to sustain annual production of 18 million pounds, later in the mine life.

Ground freezing

To manage our risks and meet our production schedule, the areas being mined must meet specific ground freezing requirements before we begin jet boring. We have identified greater variation of the freeze rates of different geological formations encountered in the mine, based on new information obtained through surface freeze drilling. As a mitigation measure, we have increased the site freeze capacity to facilitate the extraction of ore cavities as planned.

Mill modifications

There is a risk to our plan to achieve the full production rate of 18 million pounds per year by 2018 if AREVA is unable to complete and commission the required mill modification and expansion on schedule. We are working closely with AREVA to understand and help mitigate the risks to ensure that mine and mill production schedules are aligned.

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 or disruption in Cigar Lake 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 completely 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.

We also manage the risks listed on pages 51 to 52.

MANAGEMENT’S DISCUSSION AND ANALYSIS 63

Uranium – operating properties

Inkai

|  | 2014 Production (our share) |  | Proportion of 2014 U production
| 2.9M lbs |
| 2015 Production Outlook (our share) |
| 3.0M lbs |
| Estimated Reserves (our share) |
| 45.6M lbs |
| Estimated Mine Life |
| 2030 *(based on licence term) |

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) |  | 45.6 million pounds (proven and probable), average grade U3O8: 0.07%
Estimated resources (our share) |  | 30.0 million pounds (indicated), average grade U3O8: 0.08% 145.9 million pounds (inferred), average grade U3O8: 0.05%
Mining methods |  | In situ recovery (ISR)
Licensed capacity (wellfields) |  | 5.2 million pounds per year (our share 3.0 million pounds per year)
Licence term |  | Block 1: 2024, Block 2: 2030
Total production: 2008 to 2014 (our share) |  | 14.9 million pounds
2014 production (our share) |  | 2.9 million pounds (5.1 million pounds on 100% basis)
2015 production outlook (our share) |  | 3.0 million pounds (5.2 million pounds on 100% basis)
Estimated decommissioning cost (100% basis ) |  | $9 million (US)

2014 UPDATE

Production

Total production from Inkai was 5.1 million pounds; our share was 2.9 million pounds. Production was 3% lower than both our forecast for the year and our production in 2013. Inkai experienced delays in bringing on new wellfields as a result of abnormally heavy snowfall and a rapid spring melt in 2014.

Project funding

We have a loan agreement with Inkai whereby we funded Inkai’s project development costs. As of December 31, 2014, there was $55 million (US) of principal outstanding on the loan. In 2014, Inkai paid $1.8 million (US) in interest on the loan and repaid $48 million (US) of principal.

Under the loan agreement, Inkai first uses cash available every year to pay accrued interest, 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.

64 CAMECO CORPORATION

We are also currently advancing funds for Inkai’s work on block 3. As of December 31, 2014, the block 3 loan principal amounted to $136 million (US).

Production expansion

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. Their primary focus is now on uranium refining, which is an intermediate step in the uranium conversion process. A Nuclear Cooperation Agreement between Canada and Kazakhstan is in place, providing the international framework necessary for applying to the two governments for the required licences and permits. We expect to pursue further expansion of production at Inkai at a pace measured to market opportunities. Discussions continue with Kazatomprom.

Block 3 exploration

In 2014, Inkai continued construction of the test leach facility and test wellfields, and advanced work on a preliminary appraisal of the mineral potential according to Kazakhstan standards.

PLANNING FOR THE FUTURE

Production

We expect total production from blocks 1 and 2 to be 5.2 million pounds in 2015; our share is 3.0 million pounds. We expect to maintain production at this level until the potential expansion under the 2012 MOA proceeds.

Block 3 exploration

In 2015, Inkai expects to complete construction of the test leach facility and continue working on a final appraisal of the mineral potential according to Kazakhstan standards.

MANAGING OUR RISKS

Supply of sulphuric acid

There were minor weather-related interruptions to sulphuric acid supply during 2014. Given the importance of sulphuric acid to Inkai’s mining operations and shortages in previous years, we closely monitor its availability. Our production may be less than forecast if there is a shortage.

Block 3 Licence Extension

Inkai is working to extend the term of its current exploration licence, which expires in July, 2015. Although a number of extensions of the licence term have been granted by Kazakh regulatory authorities in the past, there is no assurance that a further extension will be granted. Without such extension, there is a risk we could lose our rights to block 3, and a risk we will not be compensated for the funds we advanced to Inkai to fund block 3 activities.

Political risk

Kazakhstan declared itself independent in 1991 after the dissolution of the Soviet Union. Our Inkai investment and 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 65

The principal legislation governing subsoil exploration and mining activity in Kazakhstan is the Subsoil Use Law dated June 24, 2010, and amended on December 29, 2014 (new subsoil law). 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 51 to 52.

66 CAMECO CORPORATION

Uranium – operating properties

Rabbit Lake

|  | 2014 Production 4.2M lbs 2015 Production Outlook 3.9M lbs Estimated Reserves 15.2M lbs |  | Proportion of 2014 U production

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 |  | 15.2 million pounds (proven and probable), average grade U3O8: 0.61%
Estimated resources |  | 22.2 million pounds (indicated), average grade U3O8: 0.75% 25.9 million pounds (inferred), average grade U3O8: 0.58%
Mining methods |  | Vertical blasthole stoping
Licensed capacity |  | Mill: maximum 16.9 million pounds per year; currently 11 million
Licence term |  | Through October, 2023
Total production: 1975 to 2014 |  | 198.4 million pounds
2014 production |  | 4.2 million pounds
2015 production outlook |  | 3.9 million pounds
Estimated decommissioning cost |  | $203 million

2014 UPDATE

Production

Production this year was 2% higher than both our forecast and our 2013 production as a result of planned timing of production stopes, coupled with slightly improved ore grades.

Development and production continued at Eagle Point mine. At the mill, we continued to improve performance by replacing key pieces of mill infrastructure and improving the efficiency of the mill operation schedule. The mill ran continuously for eight months and maintenance work was completed during an extended four-month summer shutdown period.

Impairment

In 2014, we recognized a $126 million impairment charge related to our Rabbit Lake operation. The impairment was due to the deferral of various projects that were related to planned production over the remaining life of the Eagle Point mine. The amount of the charge was determined as the excess of the carrying value over the recoverable amount. The recoverable amount of the mine was determined to be $29 million. See note 10 to the financial statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS 67

Exploration

We continued our underground drilling program to delineate resources northeast of the current mine workings, and below active mining areas. As a result, we added additional resources at Rabbit Lake. See Mineral reserves and resources on page 79 for more information.

PLANNING FOR THE FUTURE

Production

We expect to produce 3.9 million pounds in 2015.

Tailings capacity

We expect to have sufficient tailings capacity to support milling of Eagle Point ore until about 2018 (based upon expected ore tonnage and milling rates).

In 2015, we are continuing to evaluate options, including expansion of the existing Rabbit Lake In-pit Tailings Management Facility, or a possible north pit expansion to allow for tailings deposition into the future. An expansion of existing tailings capacity is required to support future mining at Eagle Point, and provide additional tailings capacity to process ore from other potential sources. Depending upon the chosen option, we may need an environmental assessment and regulatory approval to proceed with any increase in capacity.

Exploration

We plan to continue our underground drilling reserve replacement program in areas of interest east and northeast of the mine in 2015. The drilling will be carried out from underground locations.

Reclamation

As part of our multi-year site-wide reclamation plan, we spent over $0.9 million in 2014 to reclaim facilities that are no longer in use and plan to spend over $0.5 million in 2015.

MANAGING OUR RISKS

We manage the risks listed on pages 51 to 52.

68 CAMECO CORPORATION

Uranium – operating properties

Smith Ranch-Highland & Satellite Facilities

|  | 2014 Production 2.1M lbs 2015 Production Outlook 1.4M lbs Estimated Reserves 7.7M lbs |  | Proportion of 2014 U production

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, including uranium from satellite facilities. The Highland plant is currently idle. Together, they form the largest uranium production facility in the United States.

Location |  | Wyoming, US
Ownership |  | 100%
End product |  | Uranium concentrates
ISO certification |  | ISO 14001 certified
Estimated reserves |  | Smith Ranch-Highland: 4.8 million pounds (proven and probable), average grade U3O8: 0.09% North Butte-Brown Ranch: 2.9 million pounds (proven and probable), average grade U3O8: 0.08%
Estimated resources |  | Smith Ranch-Highland: 21.6 million pounds (measured and indicated), average grade U3O8: 0.06% 7.9 million pounds (inferred), average grade U3O8: 0.05% North Butte-Brown Ranch 8.8 million pounds (measured and indicated), average grade U3O8: 0.07% 0.4 million pounds (inferred), average grade U3O8: 0.07%
Mining methods |  | In situ recovery (ISR)
Licensed capacity |  | Wellfields: 3 million pounds per year Processing plants: 5.5 million pounds per year, including Highland mill
Licence term |  | Pending renewal – see Production below
Total production: 2002 to 2014 |  | 19.7 million pounds
2014 production |  | 2.1 million pounds
2015 production outlook |  | 1.4 million pounds
Estimated decommissioning cost |  | Smith Ranch-Highland: $198 million (US) North Butte: $22 million (US)

2014 UPDATE

Production

Production this year was 5% higher than our forecast and 24% higher than 2013 production, with new mine units and the North Butte satellite contributing to production at Smith Ranch-Highland in 2014.

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

PLANNING FOR THE FUTURE

Production

In 2015, we expect to produce 1.4 million pounds. The decrease is a result of market conditions, which led us to defer some wellfield development.

MANAGING OUR RISKS

We manage the risks listed on pages 51 to 52.

MANAGEMENT’S DISCUSSION AND ANALYSIS 69

Uranium – operating properties

Crow Butte

|  | 2014 Production 0.6M lbs 2015 Production Outlook 0.3M lbs Estimated Reserves 1.7M lbs |  | Proportion of 2014 U production

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 |  | 1.7 million pounds (proven), average grade U3O8: 0.10%
Estimated resources |  | 14.6 million pounds (indicated), average grade U3O8: 0.27% 2.9 million pounds (inferred), average grade U3O8: 0.12%
Mining methods |  | In situ recovery (ISR)
Licensed capacity (processing plants and wellfields) |  | 2.0 million pounds per year
Licence term |  | Through October, 2024
Total production: 2002 to 2014 |  | 9.7 million pounds
2014 production |  | 0.6 million pounds
2015 production outlook |  | 0.3 million pounds
Estimated decommissioning cost |  | $45 million (US)

2014 UPDATE

Production

Production this year was as forecast, but 14% lower than 2013 production due to declining head grade.

The US Nuclear Regulatory Commission renewed our operating licence for Crow Butte during the fourth quarter of 2014. The new licence is valid for ten years, through October, 2024.

PLANNING FOR THE FUTURE

Production

In 2015, we expect to produce 0.3 million pounds. The head grade and overall production at Crow Butte is expected to continue to decline, as there are no new wellfields being developed under the current mine plan.

MANAGING OUR RISKS

We manage the risks listed on pages 51 to 52.

70 CAMECO CORPORATION

Uranium – projects under evaluation

We continue to advance our projects under evaluation toward development decisions at a pace aligned with market opportunities in order to respond should the market signal a need for more uranium.

The process 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.

Millennium

Location |  | Saskatchewan, Canada
Ownership |  | 69.9%
End product |  | Uranium concentrates
Potential mine type |  | Underground
Estimated resources (our share) |  | 53.0 million pounds (indicated), average grade U3O8: 2.39% 20.2 million pounds (inferred), average grade U3O8: 3.19%

BACKGROUND

The Millennium deposit was discovered in 2000, and was delineated through geophysical survey and drilling work between 2000 and 2013. In 2012, we paid $150 million to acquire AREVA’s 27.94% interest in the project, bringing our interest in the project to 69.9%. We are the operator.

2014 UPDATE

We have submitted the final environmental impact statement to regulators, and in 2014, we were expecting a decision from the CNSC on a construction and operating licence for Millennium. However, we requested an adjournment of the public hearing, as moving the process forward at this time is not justified in the current uranium price environment. Based on our current assessment of the uranium market, we do not expect the deferral of the CNSC hearing will impair our ability to quickly advance Millennium to a development decision when the market signals the need for additional production.

Yeelirrie

Location |  | Western Australia
Ownership |  | 100%
End product |  | Uranium concentrates
Potential mine type |  | Open pit
Estimated resources |  | 127.3 million pounds (measured and indicated), average grade U3O8: 0.16%

BACKGROUND

In 2012, we paid $430 million (US) (as well as $22 million (US) in stamp duty) to acquire the Yeelirrie uranium deposit. The deposit was discovered in 1972 and 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 71

2014 UPDATE

This year, we:

• |  | continued studies to assess the technical, environmental and financial aspects of the project

• |  | commenced environmental approvals during the fourth quarter to ensure we are able to advance the project quickly, should the market signal a need for more uranium

Kintyre

Location |  | Western Australia
Ownership |  | 70%
End product |  | Uranium concentrates
Potential 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 2008, we paid $346 million (US) to acquire a 70% interest in Kintyre. The Kintyre deposit is amenable to open pit mining techniques. In 2012, we recorded a $168 million write-down of the carrying value of our interest, due to a weakened uranium market. We are the operator.

2014 UPDATE

This year:

• |  | we carried out further exploration to test for potential satellite deposits at Kintyre and other regional exploration projects close to Kintyre, which did not produce any significant results

• |  | Western Australia’s Environmental Protection Authority recommended conditional approval of the project’s Environmental Review and Management Program; state and federal ministerial approvals are pending

MANAGING THE RISKS

For all of our projects under evaluation, we manage the risks listed on pages 51 to 52.

72 CAMECO CORPORATION

Uranium – exploration and corporate development

Our exploration program is directed at replacing mineral reserves as they are depleted by our production, and ensuring our future growth. 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 1.7 million hectares (4.2 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 may 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.

In 2014, we continued our exploration strategy of focusing on the most prospective Canadian and Australian projects in our portfolio. Exploration is key to ensuring our long-term growth, and since 2008, we have continued to invest in exploring the land we hold.

2014 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 $4.1 million on six brownfield exploration projects, $5.5 million on our projects under evaluation in Australia, and $5.0 million for resource definition at Inkai and at our US operations.

Regional exploration

We spent about $32 million on regional exploration programs (including support costs), primarily in Saskatchewan and Australia.

PLANNING FOR THE FUTURE

We plan to maintain an active uranium exploration program and continue to focus on our core projects in Saskatchewan under our long-term exploration strategy.

Brownfield exploration

In 2015, we plan to spend approximately $2.8 million on brownfield exploration in Saskatchewan and Australia. Our expenditures on projects under evaluation are expected to total $5 million.

MANAGEMENT’S DISCUSSION AND ANALYSIS 73

Regional exploration

We plan to spend about $25.6 million on 23 projects in Canada and Australia, the majority of which are at drill target stage. Among the larger expenditures planned is $6.9 million on the Read Lake project, which is adjacent to McArthur River in Saskatchewan.

ACQUISITION PROGRAM

We have a dedicated team looking for acquisition opportunities within the nuclear fuel cycle 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.

An acquisition opportunity is never assessed in isolation. Acquisitions must compete for investment capital with our own internal growth opportunities. They are subject to our capital allocation process described on page 15. Currently, given the conditions in the uranium market, and our extensive portfolio of reserves and resources, our focus is on those projects in our portfolio that provide us with the greatest certainty in the near term.

74 CAMECO CORPORATION

Fuel services

Refining, conversion and fuel manufacturing

We control about 20% of world UF6 conversion capacity and are a 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.

Blind River Refinery

|  | Licensed Capacity 24.0M kgU of UO3

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 |  | 24.0 million kgU as UO3 per year (subject to the completion of certain equipment upgrades)
Licence term |  | Through February, 2022
Estimated decommissioning cost |  | $39 million

2014 UPDATE

Production

Our Blind River refinery produced 8.9 million kgU of UO3 this year, enabling our conversion business to achieve its production targets.

MANAGING OUR RISKS

We manage the risks listed on pages 51 to 52.

MANAGEMENT’S DISCUSSION AND ANALYSIS 75

Port Hope Conversion Services

|  | Licensed Capacity 12.5M kgU of UF6 2.8M kgU of UO2

Port Hope is the only uranium conversion facility in Canada and a supplier of UO2 for Canadian-made CANDU reactors.

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
Licence term |  | Through February, 2017
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
Licence term |  | Through February, 2022
Estimated decommissioning cost |  | $20 million

2014 UPDATE

Production

Fuel services produced 11.6 million kgU, lower than our plan at the beginning of the year and 22% lower than 2013. This was a result of a decision to decrease production in response to weak market conditions.

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

The Vision in Motion project entered the feasibility stage in late 2014. We will continue with the CNSC licensing process in 2015, which is required to advance the project.

Springfields toll milling agreement

In 2014, amid the continued weak market for UF6 conversion, we paid $18 million to SFL to permit early termination of our toll-conversion agreement. Production for Cameco at the Springfields facility in the United Kingdom ceased on August 31, 2014, and the agreement ended December 31, 2014.

76 CAMECO CORPORATION

PLANNING FOR THE FUTURE

Production

We have decreased our production target for 2015 to between 9 million and 10 million kgU in response to weak market conditions.

Labour Relations

The current collective bargaining agreement for our unionized employees at CFM expires on June 1, 2015. We will commence the bargaining process in early 2015.

MANAGING OUR RISKS

We also manage the risks listed on pages 51 to 52.

MANAGEMENT’S DISCUSSION AND ANALYSIS 77

NUKEM GmbH

Offices |  | Alzenau, Germany (Headquarters, NUKEM GmbH) Connecticut, US (Subsidiary, NUKEM Inc.)
Ownership |  | 100%
Activity |  | Trading of uranium and uranium-related products
2014 sales |  | 8.11 million pounds U3O8
2015 forecast sales |  | 7 to 8 million pounds U3O8

1 | Includes sales of 1.1 million pounds and revenue of $43 million between our uranium, fuel services and NUKEM segments.

BACKGROUND

In 2013, we acquired NUKEM, one of the world’s leading traders of uranium and uranium-related products. On closing, we paid €107 million ($140 million (US)) and assumed NUKEM’s net debt of about €84 million ($111 million (US)).

NUKEM 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 multibillion-dollar market capitalizations and strong credit ratings. NUKEM also trades with converters, enrichers, other traders and investors.

NUKEM’s business model

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

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.

78 CAMECO CORPORATION

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, indicated, and inferred resources at those properties. However, only three of the properties listed in those tables are material uranium properties for us: McArthur River, Cigar Lake and Inkai.

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 eventual 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 sufficient confidence to allow the appropriate application of technical, economic, marketing, legal, environmental, social and governmental factors to support evaluation of the economic viability of the deposit.

• |  | measured resources: we can confirm both geological and grade continuity to support detailed mine 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 but it is reasonably expected that the majority of inferred mineral resources could be upgraded to indicated mineral resources with continued exploration.

Our share of uranium in the following mineral resource tables 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/or indicated mineral resources demonstrated by at least a preliminary feasibility study. The reference point at which mineral reserves are defined is the point where the ore is delivered to the processing plant. Mineral reserves fall into two categories:

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

We use current geological models, an average uranium price of $70 (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.

Our share of uranium in the mineral reserves table below 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%).

MANAGEMENT’S DISCUSSION AND ANALYSIS 79

RESERVES, MEASURED AND INDICATED (M+I) RESOURCES, INFERRED RESOURCES (WITH CHANGE FROM 2013)

at December 31, 2014

Changes this year

Our share of proven and probable mineral reserves went from 443 million pounds U3O8 at the end of 2013 to 429 million pounds at the end of 2014. The change in reserves was mainly the result of:

• |  | production, which removed 24.5 million pounds from our mineral inventory, including first production from Cigar Lake

• |  | additional drilling information at Cigar Lake from surface freezeholes

Measured and indicated mineral resources decreased from 391 million pounds U3O8 at the end of 2013 to 379 million pounds at the end of 2014. Our share of inferred mineral resources is 311 million pounds U3O8, an increase of 22 million pounds from the end of 2013

The variance in mineral resources was mainly the result of:

• |  | the addition of 1.9 million pounds of indicated resources and 16.8 million pounds of inferred resources at Rabbit Lake, primarily from delineation drilling

• |  | the removal of Dawn Lake mineral resources of 7.4 million pounds from our inventory due to uncertainty with the historical drilling data

• |  | the re-interpretation, estimate and categorization of Gas Hills/Peach resources

Qualified persons

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

MCARTHUR RIVER/KEY LAKE

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

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

• |  | Les Yesnik, general manager, Cigar Lake, Cameco

• |  | Baoyao Tang, technical superintendent, McArthur River, Cameco

CIGAR LAKE

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

• |  | Scott Bishop, manager, technical services, Cameco

• |  | Eric Paulsen, chief metallurgist, technical services, Cameco

INKAI

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

• |  | Darryl Clark, general manager, JV Inkai

• |  | Lawrence Reimann, manager, technical services, Cameco Resources

• |  | Bryan Soliz, principal geologist, mineral resources management, Cameco

80 CAMECO CORPORATION

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 pre-feasibility 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 81

Mineral reserves

As at December 31, 2014 (100% basis – only the second last column shows our share)

PROVEN AND PROBABLE

(tonnes in thousands; pounds in millions)

|  |  |  | PROVEN |  |  | PROBABLE |  |  | TOTAL MINERAL RESERVES |  |  | OUR SHARE OF CONTENT (LBS U3O8) |  |  | METALLURGICAL RECOVERY (%) |
PROPERTY |  | MINING METHOD |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  |
McArthur River |  | UG |  |  | 497.8 |  |  |  | 18.71 |  |  |  | 205.3 |  |  |  | 555.2 |  |  |  | 11.43 |  |  |  | 139.9 |  |  |  | 1,053.0 |  |  |  | 14.87 |  |  |  | 345.2 |  |  |  | 241.0 |  |  |  | 98.7 |
Cigar Lake |  | UG |  |  | 205.6 |  |  |  | 24.00 |  |  |  | 108.8 |  |  |  | 391.6 |  |  |  | 14.60 |  |  |  | 126.1 |  |  |  | 597.2 |  |  |  | 17.84 |  |  |  | 234.9 |  |  |  | 117.5 |  |  |  | 98.5 |
Rabbit Lake |  | UG |  |  | 32.7 |  |  |  | 0.26 |  |  |  | 0.2 |  |  |  | 1,093.7 |  |  |  | 0.62 |  |  |  | 15.0 |  |  |  | 1,126.4 |  |  |  | 0.61 |  |  |  | 15.2 |  |  |  | 15.2 |  |  |  | 97.0 |
Key Lake |  | OP |  |  | 67.5 |  |  |  | 0.50 |  |  |  | 0.7 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 67.5 |  |  |  | 0.50 |  |  |  | 0.7 |  |  |  | 0.6 |  |  |  | 98.7 |
Inkai |  | ISR |  |  | 1,420.5 |  |  |  | 0.08 |  |  |  | 2.6 |  |  |  | 52,999.2 |  |  |  | 0.07 |  |  |  | 76.8 |  |  |  | 54,419.7 |  |  |  | 0.07 |  |  |  | 79.4 |  |  |  | 45.6 |  |  |  | 85.0 |
Smith Ranch-Highland |  | ISR |  |  | 1,145.5 |  |  |  | 0.10 |  |  |  | 2.4 |  |  |  | 1,241.1 |  |  |  | 0.09 |  |  |  | 2.4 |  |  |  | 2,386.6 |  |  |  | 0.09 |  |  |  | 4.8 |  |  |  | 4.8 |  |  |  | 80.0 |
North Butte-Brown Ranch |  | ISR |  |  | 753.4 |  |  |  | 0.08 |  |  |  | 1.4 |  |  |  | 875.2 |  |  |  | 0.08 |  |  |  | 1.5 |  |  |  | 1,628.6 |  |  |  | 0.08 |  |  |  | 2.9 |  |  |  | 2.9 |  |  |  | 60.0 |
Crow Butte |  | ISR |  |  | 801.4 |  |  |  | 0.10 |  |  |  | 1.7 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 801.4 |  |  |  | 0.10 |  |  |  | 1.7 |  |  |  | 1.7 |  |  |  | 85.0 |
Total |  |  |  |  | 4,924.4 |  |  |  | — |  |  |  | 323.1 |  |  |  | 57,155.9 |  |  |  | — |  |  |  | 361.6 |  |  |  | 62,080.3 |  |  |  | — |  |  |  | 684.6 |  |  |  | 429.2 |  |  |  |  |

Notes

UG – underground

OP – open pit

ISR – in situ recovery

Estimates in the above table:

| • |  | use an average uranium price of $70 (US)/lb U3O8

| • |  | are based on an average exchange rate of $1.00 US=$1.05-$1.10 Cdn

| • |  | Totals may not add up due to rounding

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 provide 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. The content and our share of uranium in the table above are before accounting for estimated metallurgical recovery.

82 CAMECO CORPORATION

Mineral resources

As at December 31, 2014 (100% – only the shaded columns show our share)

MEASURED, INDICATED AND INFERRED

(tonnes in thousands; pounds in millions)

|  | MEASURED RESOURCES (M) |  |  | INDICATED RESOURCES (I) |  |  | TOTAL M+I CONTENT (LBS U3O8) |  |  | OUR SHARE TOTAL M + I CONTENT (LBS U3O8) |  |  | INFERRED RESOURCES |  |  | OUR SHARE INFERRED CONTENT (LBS U3O8) |
PROPERTY |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |  |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |
McArthur River |  |  | 100.8 |  |  |  | 3.55 |  |  |  | 7.9 |  |  |  | 12.0 |  |  |  | 10.03 |  |  |  | 2.7 |  |  |  | 10.6 |  |  |  | 7.4 |  |  |  | 350.9 |  |  |  | 7.38 |  |  |  | 57.1 |  |  |  | 39.9 |
Cigar Lake |  |  | 4.7 |  |  |  | 12.00 |  |  |  | 1.2 |  |  |  | 19.6 |  |  |  | 8.09 |  |  |  | 3.4 |  |  |  | 4.7 |  |  |  | 2.3 |  |  |  | 293.7 |  |  |  | 16.22 |  |  |  | 105.0 |  |  |  | 52.5 |
Rabbit Lake |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,338.3 |  |  |  | 0.75 |  |  |  | 22.2 |  |  |  | 22.2 |  |  |  | 22.2 |  |  |  | 2,030.6 |  |  |  | 0.58 |  |  |  | 25.9 |  |  |  | 25.9 |
Millennium |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,442.6 |  |  |  | 2.39 |  |  |  | 75.9 |  |  |  | 75.9 |  |  |  | 53.0 |  |  |  | 412.4 |  |  |  | 3.19 |  |  |  | 29.0 |  |  |  | 20.2 |
Phoenix |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 166.4 |  |  |  | 19.13 |  |  |  | 70.2 |  |  |  | 70.2 |  |  |  | 21.1 |  |  |  | 8.6 |  |  |  | 5.80 |  |  |  | 1.1 |  |  |  | 0.3 |
Tamarack |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 183.8 |  |  |  | 4.42 |  |  |  | 17.9 |  |  |  | 17.9 |  |  |  | 10.3 |  |  |  | 45.6 |  |  |  | 1.02 |  |  |  | 1.0 |  |  |  | 0.6 |
Kintyre |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 4,315.4 |  |  |  | 0.58 |  |  |  | 55.2 |  |  |  | 55.2 |  |  |  | 38.7 |  |  |  | 950.2 |  |  |  | 0.46 |  |  |  | 9.6 |  |  |  | 6.7 |
Yeelirrie |  |  | 24,013.5 |  |  |  | 0.17 |  |  |  | 92.4 |  |  |  | 12,626.5 |  |  |  | 0.13 |  |  |  | 34.9 |  |  |  | 127.3 |  |  |  | 127.3 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Inkai |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 31,091.1 |  |  |  | 0.08 |  |  |  | 52.2 |  |  |  | 52.2 |  |  |  | 30.0 |  |  |  | 253,720.2 |  |  |  | 0.05 |  |  |  | 253.8 |  |  |  | 145.9 |
Smith Ranch-Highland |  |  | 1,792.1 |  |  |  | 0.11 |  |  |  | 4.5 |  |  |  | 14,378.4 |  |  |  | 0.05 |  |  |  | 17.1 |  |  |  | 21.6 |  |  |  | 21.6 |  |  |  | 6,989.4 |  |  |  | 0.05 |  |  |  | 7.9 |  |  |  | 7.9 |
North Butte-Brown Ranch |  |  | 232.6 |  |  |  | 0.08 |  |  |  | 0.4 |  |  |  | 5,530.3 |  |  |  | 0.07 |  |  |  | 8.4 |  |  |  | 8.8 |  |  |  | 8.8 |  |  |  | 294.5 |  |  |  | 0.07 |  |  |  | 0.4 |  |  |  | 0.4 |
Gas Hills-Peach |  |  | 687.2 |  |  |  | 0.11 |  |  |  | 1.7 |  |  |  | 3,626.1 |  |  |  | 0.15 |  |  |  | 11.6 |  |  |  | 13.3 |  |  |  | 13.3 |  |  |  | 3,307.5 |  |  |  | 0.08 |  |  |  | 6.0 |  |  |  | 6.0 |
Crow Butte |  |  | 1,133.1 |  |  |  | 0.24 |  |  |  | 6.0 |  |  |  | 1,354.9 |  |  |  | 0.29 |  |  |  | 8.6 |  |  |  | 14.6 |  |  |  | 14.6 |  |  |  | 1,135.2 |  |  |  | 0.12 |  |  |  | 2.9 |  |  |  | 2.9 |
Ruby Ranch |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2,215.3 |  |  |  | 0.08 |  |  |  | 4.1 |  |  |  | 4.1 |  |  |  | 4.1 |  |  |  | 56.2 |  |  |  | 0.14 |  |  |  | 0.2 |  |  |  | 0.2 |
Shirley Basin |  |  | 89.2 |  |  |  | 0.16 |  |  |  | 0.3 |  |  |  | 1,638.2 |  |  |  | 0.11 |  |  |  | 4.1 |  |  |  | 4.4 |  |  |  | 4.4 |  |  |  | 508.0 |  |  |  | 0.10 |  |  |  | 1.1 |  |  |  | 1.1 |
Total |  |  | 28,053.2 |  |  |  | — |  |  |  | 114.4 |  |  |  | 79,938.9 |  |  |  | — |  |  |  | 388.4 |  |  |  | 502.8 |  |  |  | 379.0 |  |  |  | 270,103.0 |  |  |  | — |  |  |  | 501.0 |  |  |  | 310.6 |

Notes

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 83

Additional information

Due to the nature of our business, we are required to make estimates that affect the amount of assets and liabilities, revenues and expenses, commitments and contingencies we report. We base our estimates on our experience, our best judgment, guidelines established by the Canadian Institute of Mining, Metallurgy and Petroleum and on assumptions we believe are reasonable.

We believe the following critical accounting estimates reflect the more significant judgments used in the preparation of our financial statements. These estimates affect all of our segments, unless otherwise noted.

Decommissioning and reclamation

In our uranium and fuel services segments, 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. See Note 18 to the financial statements.

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.

In performing impairment assessments of long-lived assets, assets that cannot be assessed individually are grouped together into the smallest group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Management is required to exercise judgment in identifying these cash generating units.

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.

Commencement of production stage

When we determine that a mining property has reached the production stage, capitalization of development ceases, and depreciation of the mining property begins and is charged to earnings. Production is reached when management determines that the mine is able to produce at a consistent or sustainably increasing level. This determination is a matter of judgment. See note 2 to the financial statements for further information on the criteria that we used to make this assessment.

84 CAMECO CORPORATION

Purchase price allocations

The purchase price related to a business combination or asset acquisition is allocated to the underlying acquired assets and liabilities based on their estimated fair values at the time of acquisition. The determination of fair value requires us to make assumptions, estimates and judgments regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities. As a result, the purchase price allocation impacts our reported assets and liabilities and future net earnings due to the impact on future depreciation and amortization expense and impairment tests.

Determination of joint control

We conduct certain operations through joint ownership interests. Judgment is required in assessing whether we have joint control over the investee, which involves determining the relevant activities of the arrangement and whether decisions around relevant activities require unanimous consent. Judgment is also required to determine whether a joint arrangement should be classified as a joint venture or joint operation. Classifying the arrangement requires us to assess our rights and obligations arising from the arrangement. Specifically, management considers the structure of the joint arrangement and whether it is structured through a separate vehicle. When structured through a separate vehicle, we also consider the rights and obligations arising from the legal form of the separate vehicle, the terms of the contractual arrangements and other facts and circumstances, when relevant. This judgment influences whether we equity account or proportionately consolidate our interest in the arrangement.

Controls and procedures

We have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2014, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.

Management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (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 (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2014. In 2014, we updated our control framework to COSO 2013 as required; however, we have not made any change to our internal control over financial reporting during the 2014 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 and amendments to existing standards are not yet effective for the year ended December 31, 2014, and have not been applied in preparing the consolidated financial statements. The following standards and amendments to existing standards have been published and are mandatory for our accounting periods beginning on or after January 1, 2016, unless otherwise noted. We do not intend to early adopt any of the following amendments to existing standards and we do not expect the amendments to have a material impact on our financial statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS 85

IAS16, Property, Plant and Equipment (IAS 16) and IAS 38, Intangible Assets (IAS 38) – In May 2014, the IASB issued amendments to IAS16 and IAS 38. The amendments are to be applied prospectively. The amendments clarify the factors to be considered in assessing the technical or commercial obsolescence and the resulting depreciation period of an asset and state that a depreciation method based on revenue, is not appropriate.

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

IFRS 10, Consolidated Financial Statements (IFRS 10) and IAS 28, Investments in Associate and Joint Ventures (IAS 28) – In September 2014, the IASB issued amendments to IFRS 10 and IAS 28. The amendments provide clarification on the recognition of gains or losses upon the sale or contribution of assets between an investor and its associate or joint venture.

IFRS 5, Non-Current Assets Held for Sale and Discontinued Operations (IFRS 5) – In September 2014, the IASB issued amendments to IFRS 5. The amendments are to be applied prospectively, with earlier application permitted. Assets are generally disposed of either through sale or through distribution to owners. The amendments clarify the application of IFRS 5 when changing from one of these disposal methods to the other.

IFRS 7, Financial Instruments: Disclosures (IFRS 7) – In September 2014, the IASB issued amendments to IFRS 7. The amendments in IFRS 7 are to be applied retrospectively, with earlier application permitted. The amendments clarify the disclosure required for any continuing involvement in a transferred asset that has been derecognized. The amendments also provide guidance on disclosures regarding the offsetting of financial assets and financial liabilities in interim financial reports.

IAS 34 Interim Financial Reporting (IAS 34) – In September 2014, the IASB issued amendments to IAS 34. The amendments are to be applied retrospectively, with earlier application permitted. The amendments provide additional guidance on interim disclosures and whether they are provided in the interim financial statements or incorporated by cross-reference between the interim financial statements and other financial disclosures.

IFRS 15, Revenue from Contracts with Customers (IFRS 15) – In May 2014, the IASB issued IFRS 15. IFRS 15 is effective for periods beginning on or after January 1, 2017 and is to be applied retrospectively. IFRS 15 clarifies the principles for recognizing revenue from contracts with customers. The extent of the impact of adoption of IFRS 15 has not yet been determined.

IFRS 9, Financial Instruments (IFRS 9) – In July, 2014, the International Accounting Standards Board (IASB) issued IFRS 9. IFRS 9 replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The basis of classification depends on the entity’s business model and the contractual cash flow characteristics of the financial asset or liability. It also introduces additional changes relating to financial liabilities and aligns hedge accounting more closely with risk management.

IFRS 9 is effective for annual periods beginning on or after January 1, 2018, with early adoption of the new standard permitted. We do not intend to early adopt IFRS 9. The extent of the impact of adoption of IFRS 9 has not yet been determined.

86 CAMECO CORPORATION