EX-3 4 d134768dex3.htm EX-3

Management’s discussion and analysis

February 5, 2016

6 |  | 2015 PERFORMANCE HIGHLIGHTS
8 |  | MARKET OVERVIEW AND 2015 DEVELOPMENTS
14 |  | OUR STRATEGY
21 |  | MEASURING OUR RESULTS
23 |  | FINANCIAL RESULTS
51 |  | OUR OPERATIONS AND PROJECTS
80 |  | MINERAL RESERVES AND RESOURCES
85 |  | ADDITIONAL INFORMATION
88 |  | 2015 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, 2015. The information is based on what we knew as of February 4, 2016.

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 (US) 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 2016 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 2015 developments

• |  | the discussion under the heading Our strategy

• |  | our 2016 objectives

• |  | our expectations for uranium deliveries in 2016

• |  | 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 2016

• |  | our expectations for future tax payments and rates

• |  | our expectations for future royalty payments

• |  | our price sensitivity analysis for our uranium segment

• |  | our expectation that existing cash balances and operating cash flows will meet our anticipated 2016 capital requirements without the need for any significant additional funding, other than we may need to temporarily draw on other short-term liquidity during the course of the year

• |  | our expectations for 2016, 2017 and 2018 capital expenditures

• |  | our expectation that in 2016 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 currency exchange rates, interest rates, royalty 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 Canada Revenue Agency (CRA) and this results in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision

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

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

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

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

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

• |  | we are affected by political risks

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

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

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

• |  | our uranium suppliers fail to fulfil delivery commitments

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

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

• |  | the production increase approval at McClean Lake is delayed or not obtained, or there is a labour dispute at McClean Lake

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

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

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 under the heading Price sensitivity analysis: uranium segment

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

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

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

• |  | our decommissioning and reclamation expenses

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

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

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

• |  | our Cigar Lake development, mining and production plans succeed, 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 production increase approval at McClean Lake is approved by the regulator and there is no labour dispute at the McClean Lake mill

• |  | 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 (including an ability to renew the collective bargaining agreement with unionized employees at the Port Hope conversion facility), strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents, or other development or operating risks

MANAGEMENT’S DISCUSSION AND ANALYSIS 3

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MANAGEMENT’S DISCUSSION AND ANALYSIS 5

2015 performance highlights

Cameco performed well in 2015, navigating the challenging market conditions, while continuing to prepare for the positive long-term growth we see coming in the industry.

Financial performance

HIGHLIGHTS |  |  |
DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |  | 2015 |  |  | 2014 |  |  | CHANGE |
Revenue |  |  | 2,754 |  |  |  | 2,398 |  |  |  | 15 | %
Gross profit |  |  | 697 |  |  |  | 638 |  |  |  | 9 | %
Net earnings attributable to equity holders |  |  | 65 |  |  |  | 185 |  |  |  | (65 | )%
$ per common share (diluted) |  |  | 0.16 |  |  |  | 0.47 |  |  |  | (65 | )%
Adjusted net earnings (non-IFRS, see page 25) |  |  | 344 |  |  |  | 412 |  |  |  | (17 | )%
$ per common share (adjusted and diluted) |  |  | 0.87 |  |  |  | 1.04 |  |  |  | (16 | )%
Cash provided by operations (after working capital changes) |  |  | 450 |  |  |  | 480 |  |  |  | (6 | )%

Net earnings attributable to equity holders (net earnings) and adjusted net earnings were lower in 2015 compared to 2014. However, significant weakness in the Canadian dollar in 2015 resulted in record annual consolidated revenue of $2.8 billion, and record annual revenue from our uranium segment of $1.9 billion based on sales of 32.4 million pounds at a record Canadian dollar average realized price of $57.58 per pound. See 2015 consolidated financial results beginning on page 24 for more information.

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:

• |  | record annual production of 28.4 million pounds—4% higher than the guidance provided in our 2015 third quarter MD&A

• |  | record quarterly production of 9.6 million pounds in the fourth quarter—17% higher than in 2014, largely due to production from Cigar Lake

• |  | exceeded planned production at the Cigar Lake mine and AREVA’s McClean Lake mill

We continued to advance exploration activities, spending $2 million on four brownfield exploration projects, $4 million on our projects under evaluation in Australia, and $2 million at Inkai and our US operations. We spent about $32 million on regional exploration programs, mostly in Saskatchewan and Australia.

Updates on our other segments and investments

Production in 2015 from our fuel services segment was 16% lower than in 2014. We continue to face weak market conditions for conversion services, and have decided to further reduce production at Port Hope in 2016.

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

HIGHLIGHTS |  | 2015 |  |  | 2014 |  |  | CHANGE |
Uranium |  | Production volume (million lbs) |  |  |  |  | 28.4 |  |  |  | 23.3 |  |  |  | 22 | %
|  | Sales volume (million lbs)1 |  |  |  |  | 32.4 |  |  |  | 33.9 |  |  |  | (4 | )%
|  | Average realized price |  | ($US/lb) |  |  | 45.19 |  |  |  | 47.53 |  |  |  | (5 | )%
|  |  |  | ($Cdn/lb) |  |  | 57.58 |  |  |  | 52.37 |  |  |  | 10 | %
|  | Revenue ($ millions)1 |  |  |  |  | 1,866 |  |  |  | 1,777 |  |  |  | 5 | %
|  | Gross profit ($ millions) |  |  |  |  | 608 |  |  |  | 602 |  |  |  | 1 | %
Fuel services |  | Production volume (million kgU) |  |  |  |  | 9.7 |  |  |  | 11.6 |  |  |  | (16 | )%
|  | Sales volume (million kgU)1 |  |  |  |  | 13.6 |  |  |  | 15.5 |  |  |  | (12 | )%
|  | Average realized price |  | ($Cdn/kgU) |  |  | 23.37 |  |  |  | 19.70 |  |  |  | 19 | %
|  | Revenue ($ millions)1 |  |  |  |  | 319 |  |  |  | 306 |  |  |  | 4 | %
|  | Gross profit ($ millions) |  |  |  |  | 61 |  |  |  | 38 |  |  |  | 61 | %
NUKEM |  | Sales volume U3O8 (million lbs)1 |  |  |  |  | 10.7 |  |  |  | 8.1 |  |  |  | 32 | %
|  | Average realized price |  | ($Cdn/lb) |  |  | 48.82 |  |  |  | 44.90 |  |  |  | 9 | %
|  | Revenue ($ millions)1 |  |  |  |  | 554 |  |  |  | 349 |  |  |  | 59 | %
|  | Gross profit ($ millions) |  |  |  |  | 42 |  |  |  | 22 |  |  |  | 91 | %

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments. Please see 2015 Financial results by segment beginning on page 43.

SHARES AND STOCK OPTIONS OUTSTANDING

At February 3, 2016, we had:

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

• |  | 8,481,833 stock options outstanding, with exercise prices ranging from $19.30 to $54.38

DIVIDEND POLICY

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 7

Market overview and 2015 developments

The world needs energy

It’s no secret the world needs more energy. The world’s population increasing from 7 billion to 9 billion over the next two decades will drive the need for energy, but, even today, there are 2 billion people who lack access to electricity or have only limited access. This is unacceptable in today’s modern world, where electricity is one of the greatest contributors to quality of life. Many countries are working to fill that gap and, in many cases, to keep up with rapid growth. Nuclear energy is an important option in the world’s energy mix, and, as energy demand continues to grow, nuclear is expected to do the same.

Nuclear – an integral part of the energy mix

Today, nuclear power contributes 11% of global electricity. While that percentage is not expected to change significantly over the next two decades, nuclear power output is expected to change—increasing along with rising electricity demand. In other words, the nuclear story is a growth story.

It’s easy to see why. Nuclear power is a safe, clean, reliable, affordable, and, most importantly, baseload energy source. As a result, it is an integral part of the energy mix for many countries, and even more so as the focus on climate change and clean air intensifies. Not only does it provide baseload power—that 24-hour power required to have health care, education, transportation, and communication systems—but it does so without emitting greenhouse gases (GHGs).

Reactors – gigawatt growth

That’s why, today, we see billions of dollars being invested in nuclear around the world. By 2025, we expect to see around 113 new reactors built, more than 60 of which are under construction right now. In addition, some existing plants are also adding capacity through uprates. Although this growth will be tempered somewhat by the closure of around 55 reactors, the end result is growth in the range of 80 gigawatts of nuclear power added to the world’s grids over the next decade, and even more expected outside that time frame.

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The areas of the world where we are seeing the most growth are those with increasing populations and rapidly expanding economies. China continues to lead the way with 24 reactors under construction. India, Russia, South Korea, United Arab Emirates (UAE), and the United States are also building new reactors. Of the reactors under construction today, if startups occur as planned, 65% of those units 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 four units in the UAE. Turkey is also moving forward with plans to build eight new reactors. Bangladesh, Vietnam, Jordan, Poland, Saudi Arabia, and Egypt are a few more of the countries continuing their plans to proceed with nuclear power development.

As we expand our 10-year market analysis by one year, the net new reactor count at the end of the window changes from about 80 net new reactors previously expected by 2024, to about 58 net new reactors expected by 2025. Although this change in growth expectations impacts the expected demand in the later years of our industry outlook, it does not influence our view of the market fundamentals and is primarily a function of rolling our analysis forward. This year, the change is related to:

• |  | a number of new reactors that came online in 2015 and are now in the “Operable” category, rather than the “New build” category

• |  | several reactors that are scheduled to be shut down in 2025, which are now included in our 10-year window, as well as additional shutdowns announced in 2015, increasing the “Retirements” category

• |  | low electricity prices and flat demand, in conjunction with delays in finalizing energy policies, contributing to the announcement of construction delays for some reactors in the outermost years of the 10-year window, pushing the affected units beyond 2025 and removing them from the current “New build” category

MANAGEMENT’S DISCUSSION AND ANALYSIS 9

More reactors means more demand for uranium

Today, the world’s reactors consume around 160 million pounds of uranium annually. With the growth in reactor construction, we expect that to grow to around 220 million pounds per year by 2025—average annual growth of 3%. This does not include the strategic inventory building that usually occurs with new reactor construction, which would mean even 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.

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 several 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 10% 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.

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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 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 or to cover existing commitments, 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 continues to be 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; the majority of Japan’s reactors remain idled, meaning their inventories continue to grow and Japanese utilities will be well covered for some time; and the new reactors under construction today have not yet started to consume the inventories that have been purchased and stored for their operation.

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 three years. Consumption is a fairly simple and constant equation based on the fuel needs of operating reactors and, historically, the quantity of material contracted in the long-term market in a year has been roughly equivalent to the quantity of uranium consumed in the world’s reactors in a year. In fact, only 35% of the uranium consumed in nuclear reactors over the past three years has been replaced by utilities with long-term contracts. That’s less than 180 million pounds contracted when about 475 million pounds were used, meaning inventories and the current oversupply are being drawn down as future requirements remain uncovered. If contracting is not happening now, it will have to later; the demand has just been pushed further out in time.

2015 market developments

THE GOOD, THE BAD AND THE INDIFFERENT

As has been the case in recent years, a lot happened over the course of 2015, although the general state of the market did not see much change.

Making positive news for nuclear, as usual, was China. Not only did the country continue with its rapid reactor new build program and bring eight reactors online, but Chinese companies also signed agreements with Argentina, Romania and the UK for new reactors, illustrating the country’s commitment to nuclear and its intent to become a major international player in the nuclear industry.

Undoubtedly, the biggest headline of 2015 was the long-awaited first reactor restarts in Japan. Sendai units 1 and 2 were the first reactors in Japan to restart since 2013, and it is hoped they are the first of many to come.

New builds in the UK and US continued to be bright spots for the industry, in addition to a number of reactor life extensions approved in Japan, and the US, with utilities now considering additional extensions that could see reactor lives reaching 80 years.

However, these positive developments could not outweigh the more powerful influence of a continued sluggish global economy, geopolitical issues, concerns around growth in China, and flat electricity demand. These more general drivers had help from industry specific factors as well, such as slower new reactor construction, eight reactor shutdowns, the continued high level of inventories held by market participants, and France’s policy to reduce nuclear in their energy mix to 50% by 2025 becoming law.

In addition, supply performed relatively well, with only minor disruptions and one curtailment, unlike 2014, which saw six projects tempered or curtailed.

The end result was a market seemingly indifferent to the commotion of events that occurred throughout the year.

MANAGEMENT’S DISCUSSION AND ANALYSIS 11

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, similar to 2014. 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

The big news in Japan was the restart of Sendai units 1 and 2, which occurred in August and October. In addition, the court injunction against the two Takahama units was overturned in December, 2015, clearing the way for Takahama unit 3 to restart on January 29, 2016, with unit 4 expected to restart later in the first quarter. Ikata unit 3 has also cleared a safety inspection by the Nuclear Regulatory Authority, and four more units are in the final stages of approval. In all, three reactors are now in operation, while 23 remain under evaluation for restart.

Over the long term, Japan’s energy policy states that nuclear will make up 20 to 22% of the energy mix in the country. The billions of dollars in investment being made by Japan’s utilities suggest a high degree of confidence in reactors coming back online and meeting this target; however, public sentiment towards nuclear in Japan remains somewhat uncertain.

OTHER REGIONS

China’s remarkable nuclear growth program remains on track and the UK’s plans for new reactor construction continue to move forward. India and South Korea are also among several key regions growing their nuclear generation fleet.

In 2015, growth was tangible as 10 reactors came online—double that of 2014. These included the eight noted in China, one in Russia and one in South Korea. And seven more reactors began construction—six in China and one in the UAE, a formerly non-nuclear country with four reactors now under construction.

But, to round out the picture, eight units shut down. Five of these were in Japan, plus one in Sweden, one in Germany as part of its phase-out plans, and one in the UK—the last Magnox reactor operating in the world. In addition, there were announcements for future shutdowns in the US, where nuclear struggles to remain competitive in deregulated electricity markets and in the context of low natural gas prices.

One event that could have an effect on the future of nuclear in the US and other western countries is the UN Climate Conference COP-21 agreement, finalized in 2015. As a non-GHG emitter, nuclear could play a significant role in achieving climate change prevention goals.

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Industry prices

In 2015, the spot price declined from a high of $39 (US) per pound to a low of about $34 (US) per pound, but managed to average around $37 (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 is expected to remain somewhat discretionary in 2016.

|  | 2015 |  |  | 2014 |  |  | CHANGE |
Uranium ($US/lb U3O8)1 |  |  |  |  |  |  |  |  |  |  |  |
Average spot market price |  |  | 36.55 |  |  |  | 33.21 |  |  |  | 10 | %
Average long-term price |  |  | 46.29 |  |  |  | 46.46 |  |  |  | — |
Fuel services ($US/kgU as UF6)1 |  |  |  |  |  |  |  |  |  |  |  |
Average spot market price |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  | 7.35 |  |  |  | 7.63 |  |  |  | (4 | )%
Europe |  |  | 7.85 |  |  |  | 7.97 |  |  |  | (2 | )%
Average long-term price |  |  |  |  |  |  |  |  |  |  |  |
North America |  |  | 15.33 |  |  |  | 16.00 |  |  |  | (4 | )%
Europe |  |  | 16.38 |  |  |  | 17.00 |  |  |  | (4 | )%

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 focus on our tier-one assets and profitably produce at a pace aligned with market signals in order to increase long-term shareholder value, and to do that with an emphasis on safety, people and the environment.

URANIUM

Uranium production is central to our strategy, as it is the biggest value driver of the nuclear fuel cycle and our business. We plan to focus on our tier-one assets and manage our supply according to market conditions in order to return the best value possible. As conditions improve, we expect to meet rising demand with increased production from our best margin operations. See Uranium – production overview on page 54 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.

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

To deliver value, free cash flow must be productively reinvested in the business or returned to shareholders, which requires good execution and disciplined allocation. We have a multidisciplinary capital allocation team that evaluates all possible uses of investable capital.

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.

Today, considering the continued near-term uncertainty, we believe the best way to create value is to focus on expanding our tier-one assets and maintaining a strong balance sheet. This provides us with the opportunity to gain operating leverage as the market transitions to being demand driven, and mitigates risk in the event of a prolonged period of uncertainty.

REINVESTMENT

Before investable capital is reinvested in sustaining, capacity replacement or growth, all opportunities are ranked and only those that meet the required risk-adjusted return criteria are considered for investment. We also 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 result in residual investable capital, which we would then consider returning directly to shareholders.

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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 that reflect 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.

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.

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 sometimes provide for small discounts, often include floor prices, and some include ceiling prices, all of which are also escalated over the term of the contract.

MANAGEMENT’S DISCUSSION AND ANALYSIS 15

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 190 million pounds of U3O8 with 41 customers worldwide in our uranium segment, and commitments to sell approximately 65 million kilograms as UF6 conversion with 33 customers worldwide in our fuel services segment.

Customers – U3O8:

Five largest customers account for 47% of commitments

Customers – UF6 conversion:

Five largest customers account for 59% of commitments

MANAGING OUR CONTRACT COMMITMENTS

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 volumes 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 and 2020)

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

• |  | purchases under existing and/or new arrangements

• |  | discretionary use of inventories

• |  | market opportunities

16 CAMECO CORPORATION

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 cost of inputs such as labour and fuel.

Operating costs in our fuel services segment are mainly fixed. In 2015, labour accounted for about 51% 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.

To meet our delivery commitments, we make use of our mined production and inventories, and we purchase material where it is beneficial to do so. The cost of purchased material may be higher or lower than our other sources of supply, depending on market conditions. The cost of purchased material affects our cost of sales, which is determined by calculating the average of all of our sources of supply, including opening inventory, production and purchases.

FINANCIAL IMPACT

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 primary production to meet growing demand, which should have a positive impact on our average realized price.

In addition, as we execute our strategy to focus on tier-one production, we expect to see more stability in the unit cost of sales for our uranium segment.

MANAGEMENT’S DISCUSSION AND ANALYSIS 17

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 our corporate objectives around them within our four 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 integrate sustainable development principles and practices at each level of our organization, from our overall corporate strategy to individual employee practice in 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.

2015 Highlights:

• |  | our total recordable injury rate decreased by 10%

• |  | continued low average dose of radiation to workers while moving Cigar Lake into commercial production

• |  | awarded the John T Ryan National Safety award for McArthur River mine based on prior year performance

• |  | 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 also by keeping risks as low as reasonably achievable, and looking for opportunities to move beyond requirements.

We track our progress by monitoring the 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.

2015 Highlights:

• |  | sustained the significantly reduced uranium-to-air emissions achieved at our Port Hope Conversion facility in 2014

• |  | implemented waste management initiatives across the organization, including significant reductions of low level radioactive waste stored at our Fuel Services Division facilities

• |  | achieved a 50% reduction of surface water consumption at our McArthur River operation through increased recycling initiatives

• |  | carried out industry leading research and innovation in groundwater restoration at our US in situ recovery operations

SUPPORTIVE COMMUNITIES

Gaining the trust and support of our communities, indigenous people, and governments 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. These efforts are critical to obtaining and maintaining the necessary regulatory approvals.

2015 Highlights:

• |  | over $299 million in procurement from locally owned northern Saskatchewan companies

• |  | 1,369 local personnel from northern Saskatchewan (811 Cameco employees, 558 contractors)

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

• |  | community engagement activities at all of our operations

• |  | established relationships with five universities along with Los Alamos National Laboratory, and the United States Geological Survey in conducting groundwater restoration

18 CAMECO CORPORATION

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.

2015 Highlights:

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

• |  | ranked 26th out of 234 Canadian companies by Globe and Mail in governance practices

MONITORING AND MEASUREMENT

We take the integration of sustainable development and measurement of our performance seriously. We have been producing a Sustainable Development (SD) 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. We expect to release our next SD Report in 2016.

All of our operating sites are ISO 14001 compliant. In addition, we have now transitioned from individual site-based ISO 14001 certifications to a single corporate certification. We expect to roll the majority of our operations into this single certification.

Achievements

We are a four-time Gold award winner through the Progressive Aboriginal Relations program as judged by the Canadian Council for Aboriginal Business. We are also proud to have been named one of Canada’s Top 100 Employers, Saskatchewan’s Top Employers, Canada’s Best Diversity Employers and one of Canada’s Top Employers for Young People for the sixth year. We are a leading employer of indigenous peoples in Canada, and have procured over $3 billion in services from local suppliers in northern Saskatchewan since 2004. This year, we were also named one of the world’s most sustainable corporations by Corporate Knights, a Canadian media and research company.

In 2015, we secured approval to increase production at the McArthur River operation as a result of earning the confidence of our regulators, which—although primarily based on our safety, health and environmental performance—is also a reflection of the support we have from our neighbouring communities in northern Saskatchewan.

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

20 CAMECO CORPORATION

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.

2015 OBJECTIVES1 |  | TARGET |  | RESULTS |  |
OUTSTANDING FINANCIAL PERFORMANCE
Earnings measures |  | Achieve targeted adjusted net earnings and cash flow from operations. |  | Partially achieved |  | • adjusted net earnings were lower than the target • cash flow from operations was higher than the target
Capital management measures |  | Execute capital projects within the approved scope, cost and schedule. |  | Achieved |  | • cost performance was below the target level (under budget) • project milestones were achieved on or ahead of schedule
Cigar Lake |  | Achieve production target at Cigar Lake. |  | Exceeded |  | • production from Cigar Lake in 2015 was higher than the target
SAFE, HEALTHY AND REWARDING WORKPLACE
Workplace safety |  | Strive for no injuries at all Cameco-operated sites. Maintain a long-term downward trend in combined employee and contractor injury frequency and severity, and radiation doses. |  | Partially achieved |  | • did not meet our targeted safety measures • injury rates trended downward across the company, but fell short of targets for the year • average radiation doses remained low and stable
Rewarding workplace |  | Attract and retain the employees needed to support operations. |  | Substantially achieved |  | • overall voluntary 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 2015 • reportable environmental incidents were within the range of targeted performance
SUPPORTIVE COMMUNITIES
Build and sustain stakeholder support |  | Meet our business development obligations under our Collaboration Agreements. |  | Exceeded |  | • sourcing of northern services from northern Saskatchewan vendors was above the target • sourcing of capital projects construction services from northern Saskatchewan vendors was above the target

1 | Detailed results for our 2015 corporate objectives and the related targets will be provided in our 2016 management proxy circular prior to our Annual Meeting of Shareholders on May 11, 2016.

MANAGEMENT’S DISCUSSION AND ANALYSIS 21

2016 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.
CLEAN ENVIRONMENT
• Improve environmental performance at all sites.
SUPPORTIVE COMMUNITIES
• Build and sustain strong stakeholder support for our activities.

22 CAMECO CORPORATION

Financial results

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

24 |  | 2015 CONSOLIDATED FINANCIAL RESULTS
35 |  | OUTLOOK FOR 2016
37 |  | LIQUIDITY AND CAPITAL RESOURCES
42 |  | BALANCE SHEET
43 |  | 2015 FINANCIAL RESULTS BY SEGMENT
43 |  | URANIUM
45 |  | FUEL SERVICES
45 |  | NUKEM
46 |  | FOURTH QUARTER FINANCIAL RESULTS
46 |  | CONSOLIDATED RESULTS
48 |  | URANIUM
50 |  | FUEL SERVICES
50 |  | NUKEM

MANAGEMENT’S DISCUSSION AND ANALYSIS 23

2015 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 |  |  |  |  |  |  |  | CHANGE FROM |
DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED) |  | 2015 |  |  | 2014 |  |  | 2013 |  |  | 2014 TO 2015 |
Revenue |  |  | 2,754 |  |  |  | 2,398 |  |  |  | 2,439 |  |  |  | 15 | %
Gross profit |  |  | 697 |  |  |  | 638 |  |  |  | 607 |  |  |  | 9 | %
Net earnings attributable to equity holders |  |  | 65 |  |  |  | 185 |  |  |  | 318 |  |  |  | (65 | )%
$ per common share (basic) |  |  | 0.16 |  |  |  | 0.47 |  |  |  | 0.81 |  |  |  | (65 | )%
$ per common share (diluted) |  |  | 0.16 |  |  |  | 0.47 |  |  |  | 0.81 |  |  |  | (65 | )%
Adjusted net earnings (non-IFRS, see page 25) |  |  | 344 |  |  |  | 412 |  |  |  | 445 |  |  |  | (17 | )%
$ per common share (adjusted and diluted) |  |  | 0.87 |  |  |  | 1.04 |  |  |  | 1.12 |  |  |  | (16 | )%
Cash provided by operations (after working capital changes) |  |  | 450 |  |  |  | 480 |  |  |  | 524 |  |  |  | (6 | )%

Net earnings

Our net earnings attributable to equity holders (net earnings) in 2015 were $65 million ($0.16 per share diluted) compared to $185 million ($0.47 per share diluted) in 2014, mainly due to:

• |  | greater losses on foreign exchange derivatives due to the weakening of the Canadian dollar. See Foreign exchange on page 34 for details.

• |  | lower tax recoveries, primarily due to the write-off of our deferred tax asset in the US. See Income taxes on page 29 for details.

partially offset by:

• |  | lower impairment charges ($215 million in 2015; $327 million in 2014)

• |  | higher earnings in our uranium and fuel services segments due to higher average realized prices

• |  | higher earnings in our NUKEM segment as a result of higher volumes and average realized price

• |  | reduction of the provision related to our CRA litigation. See Income taxes on page 29 for details.

In addition, in 2014 there were a number of one-time items that contributed to the higher net earnings in 2014 compared to 2015, including:

• |  | the sale of our interest in BPLP resulting in a $127 million gain in 2014

• |  | a favourable settlement of $66 million in 2014 with respect to a dispute regarding a long-term supply contract with a utility customer

partially offset by:

• |  | payment of an early agreement termination fee of $18 million as a result of the cancellation of our toll conversion agreement with Springfields Fuels Limited (SFL), and $12 million for settlement costs with respect to early redemption of our Series C debentures in 2014

• |  | the write-off of $41 million of assets under construction in 2014 as a result of changes made to the scope of a number of projects

THREE-YEAR TREND

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

24 CAMECO CORPORATION

In 2014, our net earnings were $133 million lower than in 2013 primarily due to:

• |  | an increase in impairment charges ($70 million in 2013; $327 million in 2014)

• |  | 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

• |  | payment of an early termination fee of $18 million incurred as a result of our toll conversion agreement with SFL, and settlement costs of $12 million with respect to early termination of our Series C debentures

• |  | lower earnings from our fuel services business 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 Canadian dollar. See Foreign exchange on page 34 for more information.

partially offset by:

• |  | a $127 million gain on the sale of our interest in BPLP in 2014

• |  | higher earnings from our uranium segment due to a higher average realized price

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

• |  | lower exploration costs

• |  | higher tax recoveries resulting from higher pre-tax losses in Canada

Impairment charge on producing assets

During the fourth quarter of 2015, we recognized a $210 million impairment charge related to our Rabbit Lake operation. The impairment was due to increased uncertainty around future production sources for the Rabbit Lake mill as a result of the ongoing economic conditions. The amount of the charge was determined as the excess of carrying value over the recoverable amount. The recoverable amount of the mill was determined to be $69 million. See note 9 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 2015, 2014 and 2013.

($ MILLIONS) |  | 2015 |  |  | 2014 |  |  | 2013 |
Net earnings attributable to equity holders |  |  | 65 |  |  |  | 185 |  |  |  | 318 |
Adjustments |  |  |  |  |  |  |  |  |  |  |  |  |  |
Adjustments on derivatives (pre-tax) |  |  | 166 |  |  |  | 47 |  |  |  | 56 |
NUKEM purchase price inventory recovery |  |  | (3 | ) |  |  | (5 | ) |  |  | 14 |
Impairment charges |  |  | 215 |  |  |  | 327 |  |  |  | 70 |
Income taxes on adjustments |  |  | (99 | ) |  |  | (56 | ) |  |  | (28 | )
Write-off of assets |  |  | — |  |  |  | 41 |  |  |  | — |
Loss on exploration properties |  |  | — |  |  |  | — |  |  |  | 15 |
Gain on interest in BPLP (after tax) |  |  | — |  |  |  | (127 | ) |  |  | — |
Adjusted net earnings |  |  | 344 |  |  |  | 412 |  |  |  | 445 |

MANAGEMENT’S DISCUSSION AND ANALYSIS 25

The following table shows what contributed to the change in adjusted net earnings for 2015.

($ MILLIONS) |  |  |  |  |
Adjusted net earnings – 2014 |  |  | 412 |
Change in gross profit by segment |
(we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits) |
Uranium |  | Lower sales volume |  |  | (27 | )
|  | Lower realized prices ($US) |  |  | (76 | )
|  | Foreign exchange impact on realized prices |  |  | 245 |
|  | Higher costs |  |  | (136 | )
|  | change – uranium |  |  | 6 |
Fuel services |  | Lower sales volume |  |  | (5 | )
|  | Higher realized prices ($Cdn) |  |  | 50 |
|  | Higher costs |  |  | (22 | )
|  | change – fuel services |  |  | 23 |
NUKEM |  | Gross profit |  |  | 20 |
|  | change – NUKEM |  |  | 20 |
Other changes |  |  |  |  |  |
Higher administration expenditures |  |  | (10 | )
Lower exploration expenditures |  |  | 6 |
Lower income tax recovery |  |  | (76 | )
Contract termination fee (SFL) incurred in 2014 |  |  | 18 |
Arbitration award in 2014 |  |  | (66 | )
Debenture redemption premium incurred in 2014 |  |  | 12 |
Lower loss on disposal of assets |  |  | 1 |
Higher loss on derivatives |  |  | (40 | )
Lower loss on equity-accounted investments |  |  | 16 |
Higher foreign exchange gains |  |  | 25 |
Other |  |  | (3 | )
Adjusted net earnings – 2015 |  |  | 344 |

THREE-YEAR TREND

Our adjusted net earnings decreased from 2013 to 2014, and decreased again from 2014 to 2015.

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

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

partially offset by:

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

• |  | 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

The 17% decrease from 2014 to 2015 resulted from:

• |  | greater losses on foreign exchange derivatives due to the weakening of the Canadian dollar, see Foreign exchange on page 34 for more information

• |  | lower tax recoveries, primarily due to the write-off of our deferred tax asset in the US. See Income taxes on page 29 for details.

26 CAMECO CORPORATION

partially offset by:

• |  | higher earnings in our uranium and fuel services segments mainly due to a higher average realized price

• |  | higher earnings from our NUKEM segment mainly due to higher sales volumes and a higher average realized price

• |  | a reduction of the provision related to our CRA litigation, see Income taxes on page 29 for details

In addition, in 2014 there was a favourable settlement of $66 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher adjusted net earnings in 2014 compared to 2015. The impact of the settlement was partially offset by an early termination fee of $18 million incurred as a result of the cancellation of our toll conversion agreement with SFL and settlement costs of $12 million with respect to the early redemption of our Series C debentures in 2014.

Average realized prices

|  |  |  |  |  |  |  |  |  |  | CHANGE FROM |
|  |  |  | 2015 |  |  | 2014 |  |  | 2013 |  |  | 2014 TO 2015 |
Uranium1 |  | $US/lb |  |  | 45.19 |  |  |  | 47.53 |  |  |  | 48.35 |  |  |  | (5 | )%
|  | $Cdn/lb |  |  | 57.58 |  |  |  | 52.37 |  |  |  | 49.81 |  |  |  | 10 | %
Fuel services |  | $Cdn/kgU |  |  | 23.37 |  |  |  | 19.70 |  |  |  | 18.12 |  |  |  | 19 | %
NUKEM |  | $Cdn/lb |  |  | 48.82 |  |  |  | 44.90 |  |  |  | 42.26 |  |  |  | 9 | %

1 | Average realized foreign exchange rate ($US/$Cdn): 2015 – $1.27, 2014 – $1.10 and 2013 – $1.03.

Revenue

The following table shows what contributed to the change in revenue for 2015.

($ MILLIONS) |  |  |
Revenue – 2014 |  |  | 2,398 |
Uranium |  |  |  |
Lower sales volume |  |  | (80 | )
Higher realized prices ($Cdn) |  |  | 169 |
Change in intersegment sales |  |  | 48 |
Fuel services |  |  |  |
Lower sales volume |  |  | (37 | )
Higher realized prices ($Cdn) |  |  | 50 |
Change in intersegment sales |  |  | 4 |
NUKEM |  |  |  |
Change in revenue |  |  | 204 |
Change in intersegment sales |  |  | 23 |
Other |  |  | (25 | )
Revenue – 2015 |  |  | 2,754 |

See 2015 Financial results by segment on page 43 for more detailed discussion.

THREE-YEAR TREND

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 volumes in response to market conditions. This was partially offset by higher revenues in our uranium business due to a higher average 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.

In the third quarter of 2015, we projected our annual revenue to increase between 5% and 10%, but realized a 15% increase over 2014. One contributing factor was higher revenue in our NUKEM segment as a result of higher than expected sales volumes, which were driven by increased market activity in the fourth quarter. In addition, sales revenues in all of our operating segments increased compared to 2014 due to higher realized prices resulting from the weakening of the Canadian dollar. The realized foreign exchange rate was 1.27 compared to 1.10 in 2014.

MANAGEMENT’S DISCUSSION AND ANALYSIS 27

OUTLOOK FOR 2016

We expect consolidated revenue to decrease up to 5% in 2016, based on currently committed sales volumes, due to a planned decrease in uranium and fuel services sales volumes. If we make additional sales with deliveries in 2016, we would expect our revenue outlook to increase.

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries. As a result, our quarterly delivery patterns and, therefore, our sales volumes and revenue can vary significantly as shown below. We expect the quarterly distribution of uranium deliveries in 2016 to be weighted to the second half of the year. However, not all delivery notices have been received to date and the expected delivery pattern could change. Typically, we receive notices six months in advance of the requested delivery date.

Discontinued operation

On March 27, 2014, we completed the sale of our 31.6% limited partnership interest in BPLP, which was accounted for effective January 1, 2014. The aggregate sale price for our interest in BPLP and certain related entities was $450 million. We realized an after tax gain of $127 million on this divestiture. As a result of the transaction, we presented the results of BPLP as a discontinued operation and we revised our statement of earnings, statement of comprehensive income and statement of cash flows to reflect the change in presentation. See note 6 to the financial statements for more information.

($ MILLIONS) |  | 2015 |  |  | 2014 |
Share of earnings from BPLP and related entities |  |  | — |  |  |  | — |
Tax expense |  |  | — |  |  |  | — |
|  |  | — |  |  |  | — |
Gain on disposal of BPLP and related entities |  |  | — |  |  |  | 145 |
Tax expense on disposal |  |  | — |  |  |  | (18 | )
|  |  | — |  |  |  | 127 |
Net earnings from discontinued operations |  |  | — |  |  |  | 127 |

Corporate expenses

ADMINISTRATION

($ MILLIONS) |  | 2015 |  |  | 2014 |  |  | CHANGE |
Direct administration |  |  | 173 |  |  |  | 163 |  |  |  | 6 | %
Stock-based compensation |  |  | 14 |  |  |  | 13 |  |  |  | 8 | %
Total administration |  |  | 187 |  |  |  | 176 |  |  |  | 6 | %

Direct administration costs in 2015 were $10 million higher than in 2014 due to costs related to our collaboration agreement with the startup of Cigar Lake, increased legal costs as our CRA dispute progresses toward trial, and the effect of foreign exchange on our US subsidiaries.

28 CAMECO CORPORATION

We recorded $14 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 $13 million in 2014. See note 25 to the financial statements.

Outlook for 2016

We expect administration costs (not including stock-based compensation) to be 5% to 10% higher compared to 2015 due to increased costs related to the northern collaboration agreements and increased project work. In 2016, we are continuing to negotiate new collaboration agreements with northern communities, which could result in additional one-time payments. Due to the uncertainty of the timing for the potential signing of agreements, the cost is not included in our outlook. If agreements are signed and there is an impact on our administrative costs, we will update our outlook.

EXPLORATION

Our 2015 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 $47 million in 2014 to $40 million in 2015.

Outlook for 2016

We expect exploration expenses to be about 15% to 20% higher than they were in 2015 due to increased exploration activity at Cigar Lake.

FINANCE COSTS

Finance costs were $104 million compared to $112 million in 2014. The decrease from last year was a result of $12 million in settlement costs related to the early redemption of our Series C debentures being incurred in 2014, partially offset by higher interest on long-term debt in 2015. See note 20 to the financial statements.

FINANCE INCOME

Finance income was $5 million compared to $7 million in 2014, reflecting lower average cash balances in 2015.

GAINS AND LOSSES ON DERIVATIVES

In 2015, we recorded $281 million in losses on our derivatives compared to losses of $121 million in 2014. The increase reflects the continued weakening of the Canadian dollar compared to the US dollar in 2015. See Foreign exchange on page 34 and note 27 to the financial statements.

INCOME TAXES

We recorded an income tax recovery of $143 million in 2015 compared to a recovery of $175 million in 2014. The decrease in recovery was primarily due to the write-off of our deferred tax asset in the US, partially offset by a reduction in the provision related to our CRA litigation and a change in the distribution of earnings between jurisdictions compared to 2014. See note 22 to the financial statements.

During the fourth quarter, we reversed amounts related to our deferred tax asset in the US totaling $73 million. We determined that it was no longer probable that there would be sufficient taxable profit in the future against which the operating losses and other tax deductions could be used.

The recovery was impacted by a decrease of $42 million to our provision related to the CRA litigation. 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 2010 tax returns. We have recorded a cumulative tax provision of $50 million (September 30, 2015 - $92 million), where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through 2015. We have reduced the provision to reflect management’s revised estimate, which takes into account additional contract information. We are confident that we will be successful in our case and continue to believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution. See note 22 to the financial statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS 29

In 2015, we recorded losses of $960 million in Canada compared to $841 million in 2014, while earnings in foreign jurisdictions increased to $880 million from $722 million. The tax rate in Canada is higher than the average of the rates in the foreign jurisdictions in which our subsidiaries operate.

In the third quarter, we expected our annual income tax rate, based on adjusted net earnings, to be a recovery of 25% to 30%. The actual result was a recovery of 15%, mainly due to one-time adjustments as discussed above. On an adjusted earnings basis, we recognized a tax recovery of $44 million in 2015 compared to a recovery of $120 million in 2014. Our effective tax rate was a recovery of 15% in 2015, compared to a recovery of 41% in 2014. The table below presents our adjusted earnings and adjusted income tax expenses attributable to Canadian and foreign jurisdictions.

($ MILLIONS) |  | 2015 |  |  | 2014 |
Pre-tax adjusted earnings1 |  |  |  |  |  |  |  |
Canada |  |  | (578 | ) |  |  | (611 | )
Foreign |  |  | 877 |  |  |  | 901 |
Total pre-tax adjusted earnings |  |  | 299 |  |  |  | 290 |
Adjusted income taxes1 |  |  |  |  |  |  |  |
Canada |  |  | (177 | ) |  |  | (156 | )
Foreign |  |  | 133 |  |  |  | 36 |
Adjusted income tax recovery |  |  | (44 | ) |  |  | (120 | )

1 | Pre-tax adjusted earnings and adjusted income taxes are non-IFRS measures. Our IFRS-based measures have been adjusted by the amounts reflected in the table in adjusted net earnings (non-IFRS measure on page 25).

TRANSFER PRICING DISPUTES

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

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

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

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

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 2010, CRA has shifted CEL’s income (as recalculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2009, transfer pricing penalties. There has not yet been a decision regarding a transfer pricing penalty for 2010. The IRS is also proposing to allocate a portion of CEL’s income for the years 2009 through 2012 to the US, resulting in such income being taxed in multiple jurisdictions. Taxes of approximately $320 million for the 2003 – 2015 years have already been paid in a jurisdiction outside Canada and the US. Bilateral international tax treaties contain provisions that generally seek to prevent taxation of the same income in both countries. As such, in connection with these disputes, we are considering our options, including remedies under international tax treaties that would limit double taxation; however, there is a risk that we will not be successful in eliminating all potential double taxation. The expected income adjustments under our tax disputes are represented by the amounts claimed by CRA and IRS and are described below.

30 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. To the end of 2014, we received notices of reassessment for our 2003 through 2009 tax returns, and, in the fourth quarter of 2015, we received a notice of reassessment for our 2010 tax year. We have recorded a cumulative tax provision of $50 million (September 30, 2015 - $92 million), where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through 2015. We have reduced the provision to reflect management’s revised estimate, which takes into account additional contract information. We are confident that we will be successful in our case and continue to believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

For the years 2003 through 2010, CRA issued notices of reassessment for approximately $3.4 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $1.1 billion. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229 million. The Canadian income tax rules include provisions that require larger companies like us to remit or otherwise secure 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions, we have paid a net amount of $232 million cash. In addition, we have provided $332 million in letters of credit (LC) to secure 50% of the cash taxes and related interest amounts reassessed in 2015. The amounts paid or secured are shown in the table below.

YEAR PAID ($ MILLIONS) |  | CASH TAXES |  |  | INTEREST AND INSTALMENT PENALTIES |  |  | TRANSFER PRICING PENALTIES |  |  | TOTAL |  |  | CASH REMITTANCE |  |  | SECURED BY LC |
Prior to 2013 |  |  | — |  |  |  | 13 |  |  |  | — |  |  |  | 13 |  |  |  | 13 |  |  |  | — |
2013 |  |  | 1 |  |  |  | 9 |  |  |  | 36 |  |  |  | 46 |  |  |  | 46 |  |  |  | — |
2014 |  |  | 106 |  |  |  | 47 |  |  |  | — |  |  |  | 153 |  |  |  | 153 |  |  |  | — |
2015 |  |  | 202 |  |  |  | 71 |  |  |  | 79 |  |  |  | 352 |  |  |  | 20 |  |  |  | 332 |
Total |  |  | 309 |  |  |  | 140 |  |  |  | 115 |  |  |  | 564 |  |  |  | 232 |  |  |  | 332 |

Using the methodology we believe CRA will continue to apply, and including the $3.4 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $7.0 billion of additional income taxable in Canada for the years 2003 through 2015, which would result in a related tax expense of approximately $2.1 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 $1.65 billion and $1.70 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 $825 million and $850 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. Recently, the CRA decided to disallow the use of any loss carry-backs for any transfer pricing adjustment, starting with the 2008 tax year. This does not impact the anticipated income tax expense for a particular year, but does impact the timing of any required security or payment. As noted above, for the 2010 tax year, as an alternative to paying cash, we used letters of credit to satisfy our obligations related to the reassessed income tax and related interest amounts. We expect to be able to continue to provide security in the form of letters of credit to satisfy these requirements. The estimated amounts summarized in the table below reflect actual amounts paid or secured and estimated future amounts owing based on the actual and expected reassessments for the years 2003 through 2015, and include the expected timing adjustment for the inability to use any loss carry-backs starting in 2008. We will update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2015.

MANAGEMENT’S DISCUSSION AND ANALYSIS 31

$ MILLIONS |  | 2003-2015 |  |  | 2016-2017 |  |  | 2018-2023 |  |  | TOTAL |
50% of cash taxes and transfer pricing penalties paid, secured or owing in the period |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash payments |  |  | 156 |  |  |  | 155 - 180 |  |  |  | 30 - 55 |  |  |  | 335 - 360 |
Secured by letters of credit |  |  | 264 |  |  |  | 95 - 120 |  |  |  | 20 - 45 |  |  |  | 425 - 450 |
Total paid1 |  |  | 420 |  |  |  | 255 - 280 |  |  |  | 65 - 90 |  |  |  | 825 - 850 |

1 | These amounts do not include interest and instalment penalties, which totaled approximately $140 million to December 31, 2015.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted, including the $564 million already paid or otherwise secured to date.

We are expecting the trial for the 2003, 2005 and 2006 reassessments to commence during the week of September 26, 2016, with final arguments in April 2017. If this timing is adhered to, we expect to receive a Tax Court decision within six to 18 months after the trial is complete.

IRS dispute

In the fourth quarter of 2015, we received a Revenue Agents Report (RAR) from the IRS for the tax years 2010 to 2012. Similar to the 2009 RAR received in the first quarter of 2015, the IRS is challenging the transfer pricing used under certain intercompany transactions pertaining to the 2010 to 2012 tax years for certain of our US subsidiaries. The 2009 and 2010 to 2012 RARs list the adjustments proposed by the IRS and calculate the tax and any penalties owing based on the proposed adjustments.

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

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

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

The proposed adjustments result in an increase in taxable income in the US of approximately $419 million (US) and a corresponding increased income tax expense of approximately $122 million (US) for the 2009 through 2012 taxation years, with interest being charged thereon. In addition, the IRS proposed cumulative penalties of approximately $8 million (US) in respect of the adjustment.

We believe that the conclusions of the IRS in the RARs are incorrect and we are contesting them in an administrative appeal, during which we are not required to make any cash payments. 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 • Transfer pricing methodology used for certain intercompany uranium sale and purchase agreements • Allocates Cameco Europe Ltd. (CEL) income (as adjusted) for 2003 through 2010 to Canada (same income we paid tax on in foreign jurisdictions and includes income that IRS is proposing to tax) |  | • Income earned on sales of uranium by the US mines to CEL is inadequate • Compensation earned by Cameco Inc., one of our US subsidiaries, is inadequate • Allocates a portion of CEL’s income for the years 2009 through 2012 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 2010 • Auditing 2011 to 2012 |  | • IRS has proposed adjustments for 2009 through 2012

32 CAMECO CORPORATION

Timing of resolution |  | • Expect our appeal of the 2003, 2005 and 2006 reassessments to commence during the week of September 26, 2016, with final arguments expected in April 2017 • Expect Tax Court decision six to 18 months after completion of trial |  | • Contesting proposed adjustments in an administrative appeal • We cannot yet provide an estimate as to the timeline for resolution
Required payments |  | • Expect to provide security in form of letters of credit and/or make cash payments for 50% of cash taxes, interest and penalties as reassessed • Paid $232 million in cash to date • Secured $332 million using letters of credit |  | • No security or cash payments required while under administrative appeal

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 2011 through 2015 using a similar methodology as for the years 2003 through 2010, and the reassessments will be issued on the basis we expect

• |  | we will be able to apply elective deductions and utilize letters of credit to the extent anticipated

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

• |  | we will be substantially successful in our dispute with CRA and the cumulative tax provision of $50 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date

• |  | IRS may propose adjustments for later years subsequent to 2012

• |  | 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 2011 through 2015 using a different methodology than for years 2003 through 2010, or we are unable to utilize elective deductions or letters of credit to the extent anticipated, resulting in the required cash payments or security provided 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 2013 through 2015 using a different methodology than for 2009 through 2012

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

OUTLOOK FOR 2016

On an adjusted net earnings basis, we expect a tax recovery of 25% to 30% in 2016 from our uranium, fuel services and NUKEM segments.

Our consolidated tax rate is a blend of the statutory rates applicable to taxable income earned or tax losses incurred in Canada and in our foreign subsidiaries. We have a global customer base and we have established a marketing and trading structure involving foreign subsidiaries, which entered into various intercompany purchase and sale arrangements, 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.

This year, many of the existing intercompany purchase and sale arrangements in our portfolio expire. We have started to replace these contracts and will continue to put new intercompany arrangements in place, which, as the existing arrangements did, will reflect the market at the time they are signed.

MANAGEMENT’S DISCUSSION AND ANALYSIS 33

As a result, in 2017, we expect our consolidated tax rate will transition to a modest expense, and trend toward a tax expense of approximately 20% over the next five years. The actual effective tax rate will vary from year-to-year, primarily due to the actual distribution of earnings among jurisdictions and the market conditions at the time transactions occur under both our intercompany and third-party purchase and sale arrangements.

FOREIGN EXCHANGE

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

We sell the majority of our uranium and fuel services products under long-term contracts, which are routinely denominated in US dollars, while our production costs are largely denominated in Canadian dollars. To provide cash flow predictability and certainty as we undertake our operating and capital expenditures, we use hedging to try to protect our net exposure (e.g. total sales less US dollar expenses and product purchases) against shorter term exchange rate volatility.

Our risk management policy permits us to hedge 35% to 100% of our expected net exposure over a rolling 60-month period. Our normal practice is to hedge over a three- to four-year period by hedging 50% to 80% of net exposure in the first 12 months with decreasing hedge ratios in subsequent years. The actual hedge position is reflected in Revenue, cash flow and earnings sensitivity analysis provided on page 35.

In the reporting period, some hedge contracts may be settled and the remaining contracts outstanding, we mark-to-market, which can result in reported gains or losses on derivatives for the period depending on the movement in the US/Cdn exchange rate. In periods of rapid currency fluctuations, the average exchange rate under our hedge contracts will lag the market. For example, the average US/Cdn exchange rate for our 2015 hedge position included exchange rates for periods prior to the rapid devaluation of the Canadian dollar and was much lower than the average exchange rate for 2015. As a result, as a Canadian dollar reporter, we reported significant losses on derivatives in 2015. However, over time and as we add hedges at current market rates, we expect to realize the benefit of the weak Canadian dollar as the average exchange rate under our hedge contracts increases. In the event of a rapidly appreciating Canadian dollar, we would see the opposite effect.

Since we use hedging to protect our foreign exchange exposure in a particular period, when we put contracts in place we designate them for use in that period. Therefore, a portion of the reported gains and losses noted above do not apply in the current period. We take this into account in our adjusted net earnings measure, with the goal of better matching the benefits of our hedging activities with the expected foreign currency exposure to which they apply. In our adjusted net earnings measure, we adjust net earnings in the reporting period for one-time items that are not representative of our ongoing operations and to:

• |  | remove mark-to-market gains or losses on the outstanding hedge position at the end of the period

• |  | remove the portion of gains and losses on those contracts that were rolled over in the reporting period for use in a future period

• |  | add back gains and losses previously removed and that apply to the current period

At December 31, 2015:

• |  | The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.38 (Cdn), up from $1.00 (US) for $1.16 (Cdn) at December 31, 2014. The exchange rate averaged $1.00 (US) for $1.28 (Cdn) over the year.

• |  | We had foreign currency forward contracts of $1.0 billion (US), EUR 12 million and foreign currency options of $250 million (US) at December 31, 2015. The US currency forward contracts had an average exchange rate of $1.00 (US) for $1.23 (Cdn) and US currency option contracts had an average exchange rate range of $1.00 (US) for $1.28 to $1.34 (Cdn), and €1.00 for $1.11 (US) for EUR currency contracts.

• |  | The mark-to-market loss on all foreign exchange contracts was $167 million compared to a $67 million loss at December 31, 2014.

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2015, with the exception of the EUR hedge, all of our counterparties to foreign exchange hedging contracts had a Standard & Poor’s (S&P) credit rating of A or better.

34 CAMECO CORPORATION

Outlook for 2016

Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals, while maintaining the ability to respond to conditions as they evolve.

Our outlook for 2016 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 2015 Financial results by segment on page 43 for details.

2016 FINANCIAL OUTLOOK

|  | CONSOLIDATED |  |  | URANIUM |  |  | FUEL SERVICES |  |  | NUKEM |
Production |  |  | — |  |  |  | 30.0 million lbs |  |  |  | 8 to 9 million kgU |  |  |  | — |
Delivery volume1 |  |  | — |  |  |  | 30 to 32 million lbs | 2 |  |  | Decrease up to 5% |  |  |  | 9 to 10 million lbs U3O8 |
Revenue compared to 20153 |  |  | Decrease up to 5% |  |  |  | Decrease up to 5% | 4 |  |  | Increase up to 5% |  |  |  | Increase 5% to 10% |
Average unit cost of sales (including D&A) |  |  | — |  |  |  | Increase up to 5% | 5 |  |  | Increase 10% to 15% |  |  |  | — |
Direct administration costs compared to 20156 |  |  | Increase 5% to 10% |  |  |  | — |  |  |  | — |  |  |  | — |
Gross profit |  |  | — |  |  |  | — |  |  |  | — |  |  |  | Gross profit 4% to 5% |
Exploration costs compared to 2015 |  |  | — |  |  |  | Increase 15% to 20% |  |  |  | — |  |  |  | — |
Tax rate7 |  |  | Recovery of 25% to 30% |  |  |  | — |  |  |  | — |  |  |  | — |
Capital expenditures |  | $ | 320 million |  |  |  | — |  |  |  | — |  |  |  | — |

1 | Our 2016 outlook for delivery volume in our uranium and NUKEM segments does not include sales between our uranium, fuel services and NUKEM segments.

2 | Our uranium delivery volume is based on the volumes we currently have commitments to deliver under contract in 2016.

3 | For comparison of our 2016 outlook and 2015 results for revenue in our uranium and NUKEM segments, we do not include sales between our uranium, fuel services and NUKEM segments.

4 | Based on a uranium spot price of $34.65 (US) per pound (the Ux spot price as of February 1, 2016), a long-term price indicator of $44.00 (US) per pound (the Ux long-term indicator on January 25, 2016) and an exchange rate of $1.00 (US) for $1.25 (Cdn).

5 | This increase is based on the unit cost of sales for produced material and committed long-term purchases. If we make discretionary purchases in 2016, then we expect the overall unit cost of sales may be affected.

6 | Direct administration costs do not include stock-based compensation expenses. See page 28 for more information.

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

REVENUE, CASH FLOW AND EARNINGS SENSITIVITY ANALYSIS

For 2016:

• |  | An increase of $5 (US) per pound in each of the Ux spot price ($34.65 (US) per pound on February 1, 2016) and the Ux long-term price indicator ($44.00 (US) per pound on January 25, 2016) would change revenue by $72 million and net earnings by $56 million. Conversely, a decrease of $5 (US) per pound would decrease revenue by $69 million and net earnings by $54 million.

• |  | A one cent change in the value of the Canadian dollar versus the US dollar would change adjusted net earnings by $8 million and cash flow by $1 million, with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact.

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

The following table and graph are not forecasts of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table and graph. They are designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2015 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on December 31, 2015, and none of the assumptions we list below change.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 35

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 |
2016 |  |  | 41 |  |  |  | 46 |  |  |  | 56 |  |  |  | 65 |  |  |  | 75 |  |  |  | 84 |  |  |  | 93 |
2017 |  |  | 39 |  |  |  | 46 |  |  |  | 56 |  |  |  | 67 |  |  |  | 78 |  |  |  | 87 |  |  |  | 94 |
2018 |  |  | 39 |  |  |  | 47 |  |  |  | 58 |  |  |  | 69 |  |  |  | 80 |  |  |  | 90 |  |  |  | 97 |
2019 |  |  | 39 |  |  |  | 47 |  |  |  | 59 |  |  |  | 70 |  |  |  | 79 |  |  |  | 88 |  |  |  | 94 |
2020 |  |  | 42 |  |  |  | 49 |  |  |  | 59 |  |  |  | 70 |  |  |  | 79 |  |  |  | 86 |  |  |  | 93 |

The table and graph illustrate the mix of long-term contracts in our December 31, 2015 portfolio, and are consistent with our marketing strategy. Both have been updated to reflect deliveries made and contracts entered into up to December 31, 2015.

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

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

Sales

• |  | sales volumes on average of 27 million pounds per year, with commitment levels in 2016 through 2018 higher than in 2019 and 2020

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

Deliveries

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

Annual inflation

• |  | is 2% in the US

Prices

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

36 CAMECO CORPORATION

Liquidity and capital resources

At the end of 2015, we had cash and short-term investments of $459 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. Due to the cyclical nature of our business, we may need to temporarily draw on other short-term liquidity during the course of the year. However, apart from these short-term fluctuations, we expect our cash balances and operating cash flows will meet our capital requirements during 2016, without the need for significant additional funding.

We have an ongoing dispute with CRA, see page 30 for more information. Until this dispute is settled, we expect to pay cash or provide security in the form of letters of credit 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, secured or owing in the table on page 32.

FINANCIAL CONDITION

|  | 2015 |  |  | 2014 |
Cash position ($ millions) |  |  | 459 |  |  |  | 567 |
(cash and cash equivalents) |  |
Cash provided by continuing operations ($ millions) |  |  | 450 |  |  |  | 480 |
(net cash flow generated by our operating activities after changes in working capital) |  |
Cash provided by operations/net debt |  |  | 44 | % |  |  | 52 | %
(net debt is total consolidated debt, less cash position) |  |
Net debt/total capitalization |  |  | 16 | % |  |  | 15 | %
(total capitalization is net debt and equity) |  |

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, 2015:

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

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

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 37

Liquidity

($ MILLIONS) |  | 2015 |  |  | 2014 |
Cash and cash equivalents at beginning of year |  |  | 567 |  |  |  | 188 |
Cash from operations |  |  | 450 |  |  |  | 480 |
Investment activities |  |  |  |  |  |  |  |
Additions to property, plant and equipment and acquisitions |  |  | (359 | ) |  |  | (480 | )
Discontinued operation |  |  | — |  |  |  | 447 |
Other investing activities |  |  | 18 |  |  |  | 12 |
Financing activities |  |  |  |  |  |  |  |
Change in debt |  |  | — |  |  |  | 146 |
Interest paid |  |  | (70 | ) |  |  | (78 | )
Contributions from non-controlling interest |  |  | — |  |  |  | 1 |
Issue of shares |  |  | — |  |  |  | 6 |
Dividends |  |  | (158 | ) |  |  | (158 | )
Exchange rate on changes on foreign currency cash balances |  |  | 11 |  |  |  | 3 |
Cash and cash equivalents at end of year |  |  | 459 |  |  |  | 567 |

CASH FROM CONTINUING OPERATIONS

Cash from continuing operations was 6% lower than in 2014. This was primarily due to the settlement and rollover of contracts in our hedge portfolio which required more cash during 2015 compared to 2014, largely due to the weakening Canadian dollar, offset by higher profits in all of our segments. Not including working capital requirements, our operating cash flows in the year were down $46 million. See note 24 to the financial statements.

INVESTING ACTIVITIES

Cash used in investing includes acquisitions and capital spending.

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.

38 CAMECO CORPORATION

CAMECO’S SHARE ($ MILLIONS) |  | 2015 PLAN1 |  |  | 2015 ACTUAL |  |  | 2016 PLAN |
Sustaining capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 20 |  |  |  | 16 |  |  |  | 30 |
Cigar Lake |  |  | 10 |  |  |  | 9 |  |  |  | 25 |
Rabbit Lake |  |  | 35 |  |  |  | 33 |  |  |  | 25 |
US ISR |  |  | 5 |  |  |  | 7 |  |  |  | 5 |
Inkai |  |  | 5 |  |  |  | 1 |  |  |  | 5 |
Fuel services |  |  | 15 |  |  |  | 13 |  |  |  | 20 |
Other |  |  | 5 |  |  |  | 5 |  |  |  | 5 |
Total sustaining capital |  |  | 95 |  |  |  | 84 |  |  |  | 115 |
Capacity replacement capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 95 |  |  |  | 96 |  |  |  | 55 |
Cigar Lake |  |  | 25 |  |  |  | 26 |  |  |  | 20 |
Rabbit Lake |  |  | — |  |  |  | — |  |  |  | 10 |
US ISR |  |  | 30 |  |  |  | 27 |  |  |  | 20 |
Inkai |  |  | 15 |  |  |  | 19 |  |  |  | 15 |
Total capacity replacement capital |  |  | 165 |  |  |  | 168 |  |  |  | 120 |
Growth capital |  |  |  |  |  |  |  |  |  |  |  |
McArthur River/Key Lake |  |  | 15 |  |  |  | 13 |  |  |  | 40 |
Cigar Lake |  |  | 90 |  |  |  | 81 |  |  |  | 30 |
Inkai |  |  | 15 |  |  |  | 11 |  |  |  | 10 |
Fuel services |  |  | 5 |  |  |  | 1 |  |  |  | 5 |
Other |  |  | — |  |  |  | 1 |  |  |  | — |
Total growth capital |  |  | 125 |  |  |  | 107 |  |  |  | 85 |
Total uranium & fuel services |  |  | 385 | 1 |  |  | 359 |  |  |  | 320 |

1 | Capital spending outlook was updated to $385 million in our third quarter MD&A.

Outlook for investing activities

CAMECO’S SHARE ($ MILLIONS) |  | 2017 PLAN |  |  | 2018 PLAN |
Total uranium & fuel services |  |  | 300-350 |  |  |  | 250-300 |
Sustaining capital |  |  | 135-155 |  |  |  | 95-110 |
Capacity replacement capital |  |  | 135-150 |  |  |  | 145-160 |
Growth capital |  |  | 30-45 |  |  |  | 10-25 |

We expect total capital expenditures for uranium and fuel services to decrease by about 11% in 2016.

Major sustaining, capacity replacement and growth expenditures in 2016 include:

• |  | McArthur River/Key Lake – At McArthur River, the largest projects are the expansion of freeze capacity and mine development. Other projects include site facility and equipment purchases. At Key Lake, work will be done to expand capacity in the solvent extraction and crystallization circuits of the mill.

• |  | 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. At the mill, we plan to optimize tailings capacity and work on various mill facility and equipment replacements.

• |  | Cigar Lake – Work to expand freezing capacity 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 $350 million and $400 million in 2017. We now expect to spend between $300 million and $350 million in 2017. Due to the continued market uncertainty, we have reduced growth capital to focus on our tier-one properties.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 39

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

|  | 2016 |  |  | 2017 AND 2018 |  |  | 2019 AND 2020 |  |  | 2021 AND BEYOND |  |  | TOTAL |
DECEMBER 31 ($ MILLIONS) |  |  |  |  |
Long-term debt |  |  | — |  |  |  | — |  |  |  | 500 |  |  |  | 1,000 |  |  |  | 1,500 |
Interest on long-term debt |  |  | 69 |  |  |  | 139 |  |  |  | 110 |  |  |  | 226 |  |  |  | 544 |
Provision for reclamation |  |  | 13 |  |  |  | 80 |  |  |  | 81 |  |  |  | 801 |  |  |  | 975 |
Provision for waste disposal |  |  | 3 |  |  |  | 14 |  |  |  | — |  |  |  | — |  |  |  | 17 |
Other liabilities |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 64 |  |  |  | 64 |
Capital commitments |  |  | 55 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 55 |
Total |  |  | 140 |  |  |  | 233 |  |  |  | 691 |  |  |  | 2,091 |  |  |  | 3,155 |

We have contractual capital commitments of approximately $55 million at December 31, 2015. Certain of the contractual commitments may contain cancellation clauses; however, we disclose the commitments based on management’s intent to fulfil the contracts.

We have unsecured lines of credit of about $2.7 billion, which include the following:

• |  | A $1.25 billion unsecured revolving credit facility that matures November 1, 2019. 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, 2015, there were no amounts outstanding under this facility.

• |  | Approximately $1.4 billion in 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, for our obligations relating to the CRA dispute, and as overdraft protection. At December 31, 2015, we had approximately $1.4 billion outstanding in letters of credit.

In total 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

Debt covenants

Our revolving credit facility includes the following financial covenants:

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

• |  | other customary covenants and events of default

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

Not complying with any of these covenants could result in accelerated payment and termination of our revolving credit facility. At December 31, 2015, we complied with all covenants, and we expect to continue to comply in 2016.

40 CAMECO CORPORATION

NUKEM financing arrangements

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 8 and 16 to the financial statements for more information). In addition, NUKEM is required to pledge the underlying inventory as security against these performance obligations. As of December 31, 2015, we had $97.9 million ($70.8 million (US)) of inventory pledged as security under financing arrangements, compared with $94.4 million ($81.4 million (US)) at December 31, 2014.

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at the end of 2015:

• |  | purchase commitments

• |  | financial assurances

• |  | other arrangements

Purchase commitments

The table below is based on our purchase commitments at December 31, 2015. These commitments include a mix of fixed price and market-related contracts, and are with entities that buy and sell uranium and uranium-related products. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of purchase. We will update this table as required in our MD&A to reflect changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.

|  | 2016 |  |  | 2017 AND 2018 |  |  | 2019 AND 2020 |  |  | 2021 AND BEYOND |  |  | TOTAL |
DECEMBER 31 ($ MILLIONS) |  |  |  |  |
Purchase commitments1 |  |  | 1,036 |  |  |  | 862 |  |  |  | 391 |  |  |  | 403 |  |  |  | 2,692 |

1 | Denominated in US dollars, converted to Canadian dollars as of December 31, 2015 at the rate of $1.38.

At the end of 2015, we had committed to $2.7 billion (Cdn) for the following:

• |  | approximately 38 million pounds of U3O8 equivalent from 2016 to 2028

• |  | approximately 4 million kgU as UF6 in conversion services from 2016 to 2019

• |  | 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 as well as for our obligations relating to the CRA dispute. We are required to provide letters of credit to various regulatory agencies until decommissioning and reclamation activities are complete. We are also planning to provide letters of credit until the CRA dispute is resolved. Letters of credit are issued by financial institutions for a one-year term. At December 31, 2015 our financial assurances totaled $1.4 billion compared to $0.9 billion at December 31, 2014. The increase is mainly due to:

• |  | increased requirements for decommissioning letters of credit for Key Lake ($80 million)

• |  | obligations relating to the CRA dispute ($332 million)

• |  | exchange rate fluctuations ($65 million)

Other arrangements

We entered into a factoring arrangement where receivables arising from certain sales contracts are sold to a financial institution. Upon the sale, we assign the rights to the accounts receivable to the financial institution without recourse. This arrangement provides immediate access to cash and requires we collect payment from our customers and remit the payments to the financial institution. Expenses incurred under the arrangement are recognized within finance costs in the consolidated statement of earnings.

MANAGEMENT’S DISCUSSION AND ANALYSIS 41

In addition, NUKEM enters into arrangements with third parties where receivables arising from certain sales contracts are sold to financial institutions in exchange for cash. Upon the sale, NUKEM assigns the rights to the accounts receivable to the financial institution without recourse. These arrangements require NUKEM to satisfy its delivery obligations under the sales contracts; however, the customer is responsible for making payment directly to the financial institution. The discount at which the financial institution purchases the receivable is offset against the revenue NUKEM records on delivery of the product to the customer.

BALANCE SHEET

DECEMBER 31, ($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | 2015 |  |  | 2014 |  |  | 2013 |  |  | CHANGE 2014 TO 2015 |
Inventory |  |  | 1,285 |  |  |  | 902 |  |  |  | 913 |  |  |  | 42 | %
Total assets |  |  | 8,795 |  |  |  | 8,473 |  |  |  | 8,039 |  |  |  | 4 | %
Long-term financial liabilities |  |  | 2,500 |  |  |  | 2,448 |  |  |  | 1,915 |  |  |  | 2 | %
Dividends per common share |  |  | 0.40 |  |  |  | 0.40 |  |  |  | 0.40 |  |  |  | — |

Total product inventories increased by 42% to $1.3 billion this year due to higher levels of inventory for our uranium segment, where the quantities sold were lower than the quantities produced and purchased for the year. In 2015, total volume of product inventories for our uranium segment increased by 54%. During the year, we had the opportunity to purchase material at favourable prices, which added to our inventory position. In addition, the average cost of inventory increased by 15% due to the high cost of Cigar Lake production as it ramps up and the cost of material purchased during the year that was higher than the average cost of inventory at the beginning of the year. At December 31, 2015, our average cost for uranium was $36.72 per pound, up from $32.00 per pound at December 31, 2014.

At the end of 2015, our total assets amounted to $8.8 billion, an increase of $0.3 billion compared to 2014, primarily due to higher inventory and an increase in our deferred tax assets. In 2014, the total asset balance increased by $0.4 billion compared to 2013, primarily due to higher deferred tax assets and an increase in long-term receivables related to our CRA litigation.

The major components of long-term financial liabilities are long-term debt, the provision for reclamation, deferred sales and financial derivatives. In 2015, our balance did not change significantly. 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.

42 CAMECO CORPORATION

2015 financial results by segment

Uranium

HIGHLIGHTS |  |  |  |  | 2015 |  |  | 2014 |  |  | CHANGE |
Production volume (million lbs) |  |  |  |  |  |  | 28.4 |  |  |  | 23.3 |  |  |  | 22 | %
Sales volume (million lbs)1 |  |  |  |  |  |  | 32.4 |  |  |  | 33.9 |  |  |  | (4 | )%
Average spot price |  | ($ | US/lb | ) |  |  | 36.55 |  |  |  | 33.21 |  |  |  | 10 | %
Average long-term price |  | ($ | US/lb | ) |  |  | 46.29 |  |  |  | 46.46 |  |  |  | — |
Average realized price |  | ($ | US/lb | ) |  |  | 45.19 |  |  |  | 47.53 |  |  |  | (5 | )%
|  | ($ | Cdn/lb | ) |  |  | 57.58 |  |  |  | 52.37 |  |  |  | 10 | %
Average unit cost of sales (including D&A) |  | ($ | Cdn/lb | ) |  |  | 38.83 |  |  |  | 34.64 |  |  |  | 12 | %
Revenue ($ millions)1 |  |  |  |  |  |  | 1,866 |  |  |  | 1,777 |  |  |  | 5 | %
Gross profit ($ millions) |  |  |  |  |  |  | 608 |  |  |  | 602 |  |  |  | 1 | %
Gross profit (%) |  |  |  |  |  |  | 33 |  |  |  | 34 |  |  |  | (3 | )%

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (32,000 pounds in sales and revenue of $1.0 million in 2015, 1.4 million pounds in sales and revenue of $48 million in 2014).

Production volumes in 2015 increased by 22% compared to 2014. Lower production at our US ISR operations was more than offset by the rampup of Cigar Lake production. See Uranium – production overview on page 54 for more information.

Uranium revenues this year were up 5% compared to 2014 due to an increase of 10% in the Canadian dollar average realized price, partially offset by a decrease in sales volumes of 4%. The spot price for uranium averaged $36.55 (US) per pound in 2015, an increase of 10% compared to the 2014 average price of $33.21 (US) per pound; however, our US dollar average realized price was lower mainly due to lower 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 $1.27 compared to $1.10 in 2014.

Total cost of sales (including D&A) increased by 7% ($1.26 billion compared to $1.18 billion in 2014) due to higher unit cost of sales offset by lower sales volumes. The higher unit cost of sales was mainly the result of an increase in the volume of material purchased at prices higher than our average cost of inventory, and an increase in unit production costs related to the addition of higher costs from Cigar Lake during rampup.

The net effect was a $6 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) |  | 2015 |  |  | 2014 |  |  | CHANGE |
Produced |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 20.62 |  |  |  | 18.66 |  |  |  | 11 | %
Non-cash cost |  |  | 11.51 |  |  |  | 9.30 |  |  |  | 24 | %
Total production cost |  |  | 32.13 |  |  |  | 27.96 |  |  |  | 15 | %
Quantity produced (million lbs) |  |  | 28.4 |  |  |  | 23.3 |  |  |  | 22 | %
Purchased |  |  |  |  |  |  |  |  |  |  |  |
Cash cost1 |  |  | 46.02 |  |  |  | 38.17 |  |  |  | 21 | %
Quantity purchased (million lbs) |  |  | 12.5 |  |  |  | 7.1 |  |  |  | 76 | %
Totals |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs1 |  |  | 36.38 |  |  |  | 30.34 |  |  |  | 20 | %
Quantities produced and purchased (million lbs) |  |  | 40.9 |  |  |  | 30.4 |  |  |  | 35 | %

1 | Cash costs of purchased material in 2015 were $36.57 (US) per pound compared to $34.51 (US) per pound in 2014. In 2015, the exchange rate on purchases averaged $1.00 (US) for $1.26 (Cdn) compared to $1.00 (US) for $1.11 (Cdn) in 2014.

MANAGEMENT’S DISCUSSION AND ANALYSIS 43

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 years ended 2015 and 2014 as reported in our financial statements.

CASH AND TOTAL COST PER POUND RECONCILIATION

($ MILLIONS) |  | 2015 |  |  | 2014 |
Cost of product sold |  |  | 989.2 |  |  |  | 902.8 |
Add / (subtract) |  |  |  |  |  |  |  |
Royalties |  |  | (116.5 | ) |  |  | (91.2 | )
Standby charges |  |  | — |  |  |  | (24.8 | )
Other selling costs |  |  | (13.8 | ) |  |  | (9.0 | )
Change in inventories |  |  | 301.8 |  |  |  | (71.9 | )
Cash operating costs (a) |  |  | 1,160.7 |  |  |  | 705.9 |
Add / (subtract) |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 269.1 |  |  |  | 272.6 |
Change in inventories |  |  | 58.1 |  |  |  | (56.2 | )
Total operating costs (b) |  |  | 1,487.9 |  |  |  | 922.3 |
Uranium produced & purchased (million lbs) (c) |  |  | 40.9 |  |  |  | 30.4 |
Cash costs per pound (a ÷ c) |  |  | 28.38 |  |  |  | 23.22 |
Total costs per pound (b ÷ c) |  |  | 36.38 |  |  |  | 30.34 |

URANIUM SEGMENT OUTLOOK

We expect to produce 30.0 million pounds in 2016 and have commitments under long-term contracts to purchase approximately 9 million pounds.

Based on the contracts we have in place, and not including sales between our segments, we expect to deliver between 30 million and 32 million pounds of U3O8 in 2016. We expect the unit cost of sales to be up to 5% higher than in 2015, primarily due to the planned purchases during the year. If we make additional discretionary purchases in 2016 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 up to 5% lower than in 2015 as a result of an expected decrease in deliveries, not including sales between our segments, partially offset by a higher 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 $22.70/kg U3O8 ($10.30/lb) and a 15% royalty is charged on profit in excess of $22.70/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.

As a resource corporation in Saskatchewan, we also pay a corporate resource surcharge of 3% of the value of resource sales.

44 CAMECO CORPORATION

During the period from 2013 to 2015, transitional rules for the new profit royalty regime were applied whereby only 50% of capital costs were deductible. The remaining 50% was accumulated and will now be deductible beginning in 2016. In addition, the capital allowance related to Cigar Lake under the previous system was grandfathered and is also now deductible beginning in 2016. Based on the expected application of transitional and grandfathered capital allowance deductions, we anticipate that only the first tier of the profit royalty (10%) will apply in 2016 and 2017. As capital pools are depleted, we expect to also be subject to the top tier of the profit royalty (15%) in 2018.

Fuel services

(includes results for UF6, UO2 and fuel fabrication)

HIGHLIGHTS |  |  |  | 2015 |  |  | 2014 |  |  | CHANGE |
Production volume (million kgU) |  |  |  |  | 9.7 |  |  |  | 11.6 |  |  |  | (16 | )%
Sales volume (million kgU)1 |  |  |  |  | 13.6 |  |  |  | 15.5 |  |  |  | (12 | )%
Average realized price |  | ($Cdn/kgU) |  |  | 23.37 |  |  |  | 19.70 |  |  |  | 19 | %
Average unit cost of sales (including D&A) |  | ($Cdn/kgU) |  |  | 18.87 |  |  |  | 17.24 |  |  |  | 9 | %
Revenue ($ millions)1 |  |  |  |  | 319 |  |  |  | 306 |  |  |  | 4 | %
Gross profit ($ millions) |  |  |  |  | 61 |  |  |  | 38 |  |  |  | 61 | %
Gross profit (%) |  |  |  |  | 19 |  |  |  | 12 |  |  |  | 58 | %

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (339,000 kgU in sales and revenue of $2.9 million in 2015, 0.5 million kgU in sales and revenue of $4 million in 2014).

Total revenue increased by 4% due to a 19% increase in the realized price, partially offset by a 12% decrease in sales volumes.

The total cost of products and services sold (including D&A) decreased by 4% compared to 2014 ($258 million compared to $268 million in 2014), as a 12% decrease in sales volumes was partially offset by a 9% increase in the average unit cost of sales (including D&A). When compared to 2014, the average unit cost of sales was 9% higher due to the mix of fuel services products sold.

The net effect was a $23 million increase in gross profit.

FUEL SERVICES OUTLOOK

In 2016, we plan to produce 8 million to 9 million kgU, and we expect sales volumes, not including intersegment sales, to be up to 5% lower than in 2015. Overall revenue is expected to increase by up to 5% as lower sales volumes will be more than offset by an increase in the average realized price. We expect the average unit cost of sales (including D&A) to increase by 10% to 15%; therefore, overall gross profit will decrease as a result.

NUKEM

HIGHLIGHTS |  |  |  | 2015 |  |  | 2014 |  |  | CHANGE |
Sales volume U3O8 (million lbs)1 |  |  |  |  | 10.7 |  |  |  | 8.1 |  |  |  | 32 | %
Average realized price |  | ($Cdn/lb) |  |  | 48.82 |  |  |  | 44.90 |  |  |  | 9 | %
Cost of product sold (including D&A) |  |  |  |  | 512 |  |  |  | 327 |  |  |  | 57 | %
Revenue ($ millions)1 |  |  |  |  | 554 |  |  |  | 349 |  |  |  | 59 | %
Gross profit ($ millions) |  |  |  |  | 42 |  |  |  | 22 |  |  |  | 91 | %
Gross profit (%) |  |  |  |  | 8 |  |  |  | 6 |  |  |  | 33 | %

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (0.9 million pounds in sales and revenue of $19.3 million in 2015, 1.1 million pounds in sales and revenue of $43 million in 2014).

During 2015, NUKEM delivered 10.7 million pounds of uranium, an increase of 2.6 million pounds compared to the previous year due to an increase in market activity. Revenues from NUKEM amounted to $554 million, 59% higher than in 2014 as a result of higher sales volumes and an increase in the average realized price, mainly due to weakening of the Canadian dollar. Gross profit percentage was 8% for 2015, compared to 6% for 2014.

The net effect was a $20 million increase in gross profit.

NUKEM OUTLOOK

For 2016, NUKEM expects to deliver between 9 million and 10 million pounds of uranium. Total revenue and unit cost of sales, not including intersegment sales, is expected to increase by 5% to 10% compared to 2015; however, the overall gross profit percentage is expected to be slightly lower than 2015 at 4% to 5%.

MANAGEMENT’S DISCUSSION AND ANALYSIS 45

Fourth quarter financial results

Consolidated results

|  | THREE MONTHS ENDED |  |  |  |
HIGHLIGHTS |  | DECEMBER 31 |  |  |  |
($ MILLIONS EXCEPT WHERE INDICATED) |  | 2015 |  |  | 2014 |  |  | CHANGE |
Revenue |  |  | 975 |  |  |  | 889 |  |  |  | 10 | %
Gross profit |  |  | 282 |  |  |  | 251 |  |  |  | 12 | %
Net earnings (loss) attributable to equity holders |  |  | (10 | ) |  |  | 73 |  |  |  | (114 | )%
$ per common share (basic) |  |  | (0.03 | ) |  |  | 0.18 |  |  |  | (114 | )%
$ per common share (diluted) |  |  | (0.03 | ) |  |  | 0.18 |  |  |  | (114 | )%
Adjusted net earnings (non-IFRS, see page 25) |  |  | 151 |  |  |  | 205 |  |  |  | (26 | )%
$ per common share (adjusted and diluted) |  |  | 0.38 |  |  |  | 0.52 |  |  |  | (27 | )%
Cash provided by operations (after working capital changes) |  |  | 503 |  |  |  | 236 |  |  |  | 113 | %

NET EARNINGS

In the fourth quarter of 2015, our net loss was $10 million ($(0.03) per share diluted), a decrease of $83 million compared to net earnings of $73 million ($0.18 per share diluted) in 2014, mainly due to:

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

• |  | lower income tax recovery due to the reduction of our deferred tax asset in the US

• |  | higher impairment charges in 2015 ($210 million in 2015, $131 million in 2014)

partially offset by:

• |  | higher uranium gross profits resulting mainly from a higher average realized price and higher sales volumes

• |  | higher gross profits from our fuel services segment due to a higher average realized price

• |  | lower exploration expenditures

• |  | the reduction of our provision related to the CRA litigation

In addition, in the fourth quarter of 2014 there was a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher net earnings in the fourth quarter of 2014 compared to the same period in 2015. The impact of the settlement was partially offset by the write-off of $41 million of assets under construction as a result of changes made to the scope of a number of projects in the fourth quarter of 2014.

ADJUSTED NET EARNINGS

On an adjusted basis, our earnings this quarter were $151 million ($0.38 per share diluted) compared to $205 million ($0.52 per share diluted) (non-IFRS measure, see page 25) in 2014, mainly due to:

• |  | a lower income tax recovery primarily due to the reduction of our deferred tax asset in the US

partially offset by:

• |  | higher uranium gross profits resulting mainly from a higher average realized price and higher sales volumes

• |  | higher gross profits from our fuel services segment mainly due to a higher average realized price

• |  | lower exploration expenditures

• |  | the reduction of our provision related to the CRA litigation

In addition, in the fourth quarter of 2014 there was a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher adjusted net earnings in the fourth quarter of 2014 compared to the same period in 2015.

46 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 25 for more information. The following table reconciles adjusted net earnings with our net earnings.

|  | THREE MONTHS ENDED DECEMBER 31 |
($ MILLIONS) |  | 2015 |  |  | 2014 |
Net earnings (loss) attributable to equity holders |  |  | (10 | ) |  |  | 73 |
Adjustments |  |  |  |  |  |  |  |
Adjustments on derivatives (pre-tax) |  |  | 10 |  |  |  | 10 |
NUKEM purchase price inventory recovery |  |  | — |  |  |  | (4 | )
Impairment charges |  |  | 210 |  |  |  | 131 |
Income taxes on adjustments |  |  | (59 | ) |  |  | (46 | )
Write-off of assets |  |  | — |  |  |  | 41 |
Adjusted net earnings |  |  | 151 |  |  |  | 205 |

ADMINISTRATION

|  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
($ MILLIONS) |  | 2015 |  |  | 2014 |  |  | CHANGE |
Direct administration |  |  | 51 |  |  |  | 52 |  |  |  | (2 | )%
Stock-based compensation |  |  | 4 |  |  |  | 3 |  |  |  | 33 | %
Total administration |  |  | 55 |  |  |  | 55 |  |  |  | — |

Direct administration costs were $51 million in the quarter, $1 million lower than the same period last year due to the timing of expenditures, partially offset by higher legal costs as our CRA dispute progresses toward trial. Stock-based compensation expenses were $1 million higher than the fourth quarter of 2014. See note 25 to the financial statements.

Quarterly trends

HIGHLIGHTS |  | 2015 |  |  | 2014 |
($ MILLIONS EXCEPT PER SHARE AMOUNTS) |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |  |  | Q4 |  |  | Q3 |  |  | Q2 |  |  | Q1 |
Revenue |  |  | 975 |  |  |  | 649 |  |  |  | 565 |  |  |  | 566 |  |  |  | 889 |  |  |  | 587 |  |  |  | 502 |  |  |  | 419 |
Net earnings (loss) attributable to equity holders |  |  | (10 | ) |  |  | (4 | ) |  |  | 88 |  |  |  | (9 | ) |  |  | 73 |  |  |  | (146 | ) |  |  | 127 |  |  |  | 131 |
$ per common share (basic) |  |  | (0.03 | ) |  |  | (0.01 | ) |  |  | 0.22 |  |  |  | (0.02 | ) |  |  | 0.18 |  |  |  | (0.37 | ) |  |  | 0.32 |  |  |  | 0.33 |
$ per common share (diluted) |  |  | (0.03 | ) |  |  | (0.01 | ) |  |  | 0.22 |  |  |  | (0.02 | ) |  |  | 0.18 |  |  |  | (0.37 | ) |  |  | 0.32 |  |  |  | 0.33 |
Adjusted net earnings (non-IFRS, see page 25) |  |  | 151 |  |  |  | 78 |  |  |  | 46 |  |  |  | 69 |  |  |  | 205 |  |  |  | 93 |  |  |  | 79 |  |  |  | 36 |
$ per common share (adjusted and diluted) |  |  | 0.38 |  |  |  | 0.20 |  |  |  | 0.12 |  |  |  | 0.18 |  |  |  | 0.52 |  |  |  | 0.23 |  |  |  | 0.20 |  |  |  | 0.09 |
Earnings (loss) from continuing operations |  |  | (10 | ) |  |  | (4 | ) |  |  | 88 |  |  |  | (10 | ) |  |  | 72 |  |  |  | (146 | ) |  |  | 127 |  |  |  | 4 |
$ per common share (basic) |  |  | (0.03 | ) |  |  | (0.01 | ) |  |  | 0.22 |  |  |  | (0.02 | ) |  |  | 0.18 |  |  |  | (0.37 | ) |  |  | 0.18 |  |  |  | 0.01 |
$ per common share (diluted) |  |  | (0.03 | ) |  |  | (0.01 | ) |  |  | 0.22 |  |  |  | (0.02 | ) |  |  | 0.18 |  |  |  | (0.37 | ) |  |  | 0.18 |  |  |  | 0.01 |
Cash provided by continuing operations (after working capital changes) |  |  | 503 |  |  |  | (121 | ) |  |  | (65 | ) |  |  | 134 |  |  |  | 236 |  |  |  | 263 |  |  |  | (25 | ) |  |  | 7 |

Key things to note:

• |  | Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 70% of consolidated revenues in the fourth quarter of 2015 and 68% of consolidated revenues in the fourth quarter of 2014.

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

• |  | 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 25 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 47

Fourth quarter financial results by segment

Uranium

|  |  |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
HIGHLIGHTS |  |  |  | 2015 |  |  | 2014 |  |  | CHANGE |
Production volume (million lbs) |  |  |  |  | 9.6 |  |  |  | 8.2 |  |  |  | 17 | %
Sales volume (million lbs)1 |  |  |  |  | 11.2 |  |  |  | 10.7 |  |  |  | 5 | %
Average spot price |  | ($US/lb) |  |  | 35.45 |  |  |  | 37.13 |  |  |  | (5 | )%
Average long-term price |  | ($US/lb) |  |  | 44.00 |  |  |  | 48.00 |  |  |  | (8 | )%
Average realized price |  | ($US/lb) |  |  | 46.36 |  |  |  | 50.57 |  |  |  | (8 | )%
|  | ($Cdn/lb) |  |  | 61.24 |  |  |  | 56.78 |  |  |  | 8 | %
Average unit cost of sales (including D&A) |  | ($Cdn/lb) |  |  | 38.25 |  |  |  | 34.27 |  |  |  | 12 | %
Revenue ($ millions)1 |  |  |  |  | 687 |  |  |  | 606 |  |  |  | 13 | %
Gross profit ($ millions) |  |  |  |  | 257 |  |  |  | 240 |  |  |  | 7 | %
Gross profit (%) |  |  |  |  | 37 |  |  |  | 40 |  |  |  | (8 | )%

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (17,000 pounds in sales and revenue of $0.5 million in Q4 2015, 400,000 pounds in sales and revenue of $15 million in Q4 2014).

Production volumes this quarter were 17% higher compared to the fourth quarter of 2014, mainly as a result of higher production from the rampup of Cigar Lake production, offset by lower production at McArthur River/Key Lake, Rabbit Lake and our US ISR operations. See Uranium – production overview on page 54 for more information.

Uranium revenues were up 13% due to a 5% increase in sales volumes, which represents normal quarterly variance in our delivery schedule, and an 8% increase in the average realized price.

Average spot and long-term prices decreased, as did our US dollar average realized price due to lower prices under fixed-price contracts, and the mix of market and fixed contracts. However, the effect of foreign exchange resulted in an 8% higher Canadian dollar average realized price than the prior year. In the fourth quarter of 2015, our realized foreign exchange rate was $1.32 compared to $1.12 in the prior year.

Total cost of sales (including D&A) increased by 17% ($429 million compared to $366 million in 2014). This was the result of a 12% increase in the average unit cost of sales and a 5% increase in sales volumes.

The unit cost of sales increased due to an increase in the volume of material purchased throughout the year at prices higher than our average cost of inventory and an increase in the unit production costs related to the addition of higher cost production from Cigar Lake during rampup.

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

48 CAMECO CORPORATION

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 |  |  |  |
($/LB) |  | 2015 |  |  | 2014 |  |  | CHANGE |
Produced |  |  |  |  |  |  |  |  |  |  |  |
Cash cost |  |  | 16.04 |  |  |  | 14.19 |  |  |  | 13 | %
Non-cash cost |  |  | 10.96 |  |  |  | 7.15 |  |  |  | 53 | %
Total production cost |  |  | 27.00 |  |  |  | 21.34 |  |  |  | 27 | %
Quantity produced (million lbs) |  |  | 9.6 |  |  |  | 8.2 |  |  |  | 17 | %
Purchased |  |  |  |  |  |  |  |  |  |  |  |
Cash cost1 |  |  | 43.65 |  |  |  | 39.03 |  |  |  | 12 | %
Quantity purchased (million lbs) |  |  | 3.2 |  |  |  | 3.7 |  |  |  | (14 | )%
Totals |  |  |  |  |  |  |  |  |  |  |  |
Produced and purchased costs1 |  |  | 31.16 |  |  |  | 26.84 |  |  |  | 16 | %
Quantities produced and purchased (million lbs) |  |  | 12.8 |  |  |  | 11.9 |  |  |  | 8 | %

1 | In the fourth quarter of 2015, cash costs of purchased material were $33.79 (US) per pound compared to $35.05 (US) per pound in the same period in 2014. In the fourth quarter of 2015, the exchange rate on purchases averaged $1.00 (US) for $1.29 (Cdn) compared to $1.00 (US) for $1.11 (Cdn) during the same period in 2014.

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 2015 and 2014.

CASH AND TOTAL COST PER POUND RECONCILIATION

|  | THREE MONTHS ENDED DECEMBER 31 |
($ MILLIONS) |  | 2015 |  |  | 2014 |
Cost of product sold |  |  | 328.3 |  |  |  | 269.0 |
Add / (subtract) |  |  |  |  |  |  |  |
Royalties |  |  | (49.5 | ) |  |  | (34.5 | )
Other selling costs |  |  | (6.7 | ) |  |  | (2.3 | )
Change in inventories |  |  | 21.5 |  |  |  | 28.5 |
Cash operating costs (a) |  |  | 293.6 |  |  |  | 260.7 |
Add / (subtract) |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 100.9 |  |  |  | 96.7 |
Change in inventories |  |  | 4.3 |  |  |  | (38.0 | )
Total operating costs (b) |  |  | 398.8 |  |  |  | 319.4 |
Uranium produced & purchased (million lbs) (c) |  |  | 12.8 |  |  |  | 11.9 |
Cash costs per pound (a ÷ c) |  |  | 22.94 |  |  |  | 21.91 |
Total costs per pound (b ÷ c) |  |  | 31.16 |  |  |  | 26.84 |

MANAGEMENT’S DISCUSSION AND ANALYSIS 49

Fuel services

(includes results for UF6, UO2 and fuel fabrication)

|  |  |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
HIGHLIGHTS |  |  |  | 2015 |  |  | 2014 |  |  | CHANGE |
Production volume (million kgU) |  |  |  |  | 3.4 |  |  |  | 2.7 |  |  |  | 26 | %
Sales volume (million kgU)1 |  |  |  |  | 4.5 |  |  |  | 7.4 |  |  |  | (39 | )%
Average realized price |  | ($Cdn/kgU) |  |  | 21.88 |  |  |  | 16.92 |  |  |  | 29 | %
Average unit cost of sales (including D&A) |  | ($Cdn/kgU) |  |  | 17.18 |  |  |  | 14.78 |  |  |  | 16 | %
Revenue ($ millions)1 |  |  |  |  | 99 |  |  |  | 125 |  |  |  | (21 | )%
Gross profit ($ millions) |  |  |  |  | 21 |  |  |  | 16 |  |  |  | 31 | %
Gross profit (%) |  |  |  |  | 21 |  |  |  | 13 |  |  |  | 62 | %

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (339,000 kgU in sales and revenue of $2.9 million in Q4 2015, 0.5 million kgU in sales and revenue of $4 million in Q4 2014).

Total revenue decreased by 21% due to a 39% decrease in sales volumes, partially offset by a 29% increase in average realized price.

The total cost of sales (including D&A) decreased by 28% ($78 million compared to $109 million in the fourth quarter of 2014) mainly due to a 39% decrease in sales volumes, partially offset by an increase of 16% in the average unit cost of sales, primarily as a result of the mix of products sold.

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

NUKEM

|  |  |  | THREE MONTHS ENDED DECEMBER 31 |  |  |  |
HIGHLIGHTS |  |  |  | 2015 |  |  | 2014 |  |  | CHANGE |
Sales volume U3O8 (million lbs)1 |  |  |  |  | 3.7 |  |  |  | 3.4 |  |  |  | 9 | %
Average realized price |  | ($Cdn/lb) |  |  | 52.22 |  |  |  | 52.12 |  |  |  | — |
Cost of product sold (including D&A) |  |  |  |  | 186 |  |  |  | 156 |  |  |  | 19 | %
Revenue ($ millions)1 |  |  |  |  | 192 |  |  |  | 159 |  |  |  | 21 | %
Gross profit ($ millions) |  |  |  |  | 6 |  |  |  | 3 |  |  |  | 100 | %
Gross profit (%) |  |  |  |  | 3 |  |  |  | 2 |  |  |  | 50 | %

1 | Includes sales and revenue between our uranium, fuel services and NUKEM segments (nil in Q4 2015, 1.1 million pounds in sales and revenue of $43 million in Q4 2014).

NUKEM delivered 3.7 million pounds of uranium, an increase of 0.3 million pounds compared to 2014. NUKEM revenues amounted to $192 million compared to $159 million in 2014 due to an increase in volumes delivered.

Gross profit percentage was 3% in the fourth quarter of 2015, compared to 2% in the fourth quarter of 2014.

The net effect was a $3 million increase in gross profit.

50 CAMECO CORPORATION

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.

52 |  | MANAGING THE RISKS
54 |  | URANIUM – PRODUCTION OVERVIEW
54 |  | PRODUCTION OUTLOOK
55 |  | URANIUM – OPERATING PROPERTIES
55 |  | MCARTHUR RIVER MINE / KEY LAKE MILL
60 |  | CIGAR LAKE
65 |  | INKAI
68 |  | RABBIT LAKE
70 |  | SMITH RANCH-HIGHLAND
71 |  | CROW BUTTE
72 |  | URANIUM – PROJECTS UNDER EVALUATION
72 |  | MILLENNIUM
72 |  | YEELIRRIE
72 |  | KINTYRE
74 |  | URANIUM – EXPLORATION AND CORPORATE DEVELOPMENT
76 |  | FUEL SERVICES
76 |  | BLIND RIVER REFINERY
77 |  | PORT HOPE CONVERSION SERVICES
77 |  | CAMECO FUEL MANUFACTURING INC. (CFM)
79 |  | NUKEM GMBH

MANAGEMENT’S DISCUSSION AND ANALYSIS 51

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.

| • |  | Environment Canada has been reviewing the Metal Mining Effluent Regulations (MMER). This review could result in new limits for existing MMER substances and proposed limits for new substances that could impact our Saskatchewan operations.

| • |  | The U.S. Environmental Protection Agency is proposing to add new health and environmental protection standards to regulate byproduct materials produced by uranium in situ recovery operations. The proposed rule includes surface and subsurface standards, with a primary focus on groundwater protection, restoration and stability. Particularly concerning is the proposed requirement that groundwater must be monitored for 30 years after restoration.

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.

52 CAMECO CORPORATION

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.

At the end of 2015, our estimate of total decommissioning and reclamation costs was $975 million. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $917 million at the end of 2015 (the present value of the $975 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 $1 billion in letters of credit supporting our reclamation liabilities at the end of 2015. All of our North American operations have letters of credit in place that provide financial assurance in connection with our preliminary plans for decommissioning of 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 2015, we invested:

• |  | $77 million in environmental protection, monitoring and assessment programs, about the same as 2014

• |  | $31 million in health and safety programs, or 29% more than 2014 as a result of ventilation improvements at McArthur River

Spending on environmental programs is expected to increase slightly in 2016, while spending on health and safety programs will decrease toward 2014 levels.

Operational risks

Other operational risks and hazards include:

• |  | environmental damage

• |  | industrial and transportation accidents

• |  | labour shortages, disputes or strikes

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

• |  | shortages of required materials, supplies and equipment

• |  | transportation disruptions

• |  | electrical power interruptions

• |  | equipment failures

• |  | non-compliance with laws and licences

• |  | catastrophic accidents

• |  | fires

• |  | blockades or other acts of social or political activism

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

• |  | unusual, unexpected or adverse mining or geological conditions

• |  | underground floods

• |  | ground movement or cave-ins

• |  | tailings pipeline or dam failures

• |  | technological failure of mining methods

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 53

Uranium – production overview

Production in our uranium segment in the fourth quarter was 9.6 million pounds, 17% higher compared to the same period in 2014 primarily due to the rampup of production at Cigar Lake. Production for the year was 28.4 million pounds, 22% higher than in 2014. See Uranium - operating properties starting on page 55 for more information.

Uranium production

CAMECO SHARE |  | THREE MONTHS ENDED DECEMBER 31 |  |  | YEAR ENDED DECEMBER 31 |  |  |  |  |  |  |
(MILLION LBS) |  | 2015 |  |  | 2014 |  |  | 2015 |  |  | 2014 |  |  | 2015 PLAN1 |  |  | 2016 PLAN |
McArthur River/Key Lake |  |  | 3.8 |  |  |  | 4.4 |  |  |  | 13.3 |  |  |  | 13.3 |  |  |  | 13.7 |  |  |  | 14.0 |
Cigar Lake |  |  | 2.3 |  |  |  | 0.2 |  |  |  | 5.7 |  |  |  | 0.2 |  |  |  | 4.0 - 5.0 |  |  |  | 8.0 | 2
Inkai |  |  | 1.1 |  |  |  | 0.7 |  |  |  | 3.4 |  |  |  | 2.9 |  |  |  | 3.0 |  |  |  | 3.0 |
Rabbit Lake |  |  | 2.0 |  |  |  | 2.1 |  |  |  | 4.2 |  |  |  | 4.2 |  |  |  | 3.9 |  |  |  | 3.6 |
Smith Ranch-Highland |  |  | 0.3 |  |  |  | 0.6 |  |  |  | 1.4 |  |  |  | 2.1 |  |  |  | 1.4 |  |  |  | 1.2 |
Crow Butte |  |  | 0.1 |  |  |  | 0.2 |  |  |  | 0.4 |  |  |  | 0.6 |  |  |  | 0.3 |  |  |  | 0.2 |
Total |  |  | 9.6 |  |  |  | 8.2 |  |  |  | 28.4 |  |  |  | 23.3 |  |  |  | 26.3 - 27.3 |  |  |  | 30.0 | 2

1 | We updated our initial 2015 plan for Cigar Lake (to 5 million pounds, from between 3 and 4 million pounds) in our Q3 MD&A.

2 | Our 2016 plan for packaged production from Cigar Lake is subject to regulatory approval for an annual production limit increase at the McClean Lake mill. See Uranium – operating properties – Cigar Lake starting on page 60 for more information.

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 focus on our tier-one assets and profitably produce at a pace aligned with market signals in order to increase long-term shareholder value.

We plan to:

• |  | ensure continued safe, reliable, low-cost production from our tier-one assets – McArthur River/Key Lake, Cigar Lake and Inkai

• |  | complete rampup of production at Cigar Lake

• |  | seek to expand production at McArthur River/Key Lake in conjunction with market signals

• |  | manage the rest of our 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

54 CAMECO CORPORATION

Uranium – operating properties

McArthur River mine / Key Lake mill

|  | 2015 Production (our share) 13.3M lbs 2016 Production Outlook (our share) 14.0M lbs Estimated Reserves (our share) 234.9M 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 19 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 |  | McArthur River – 69.805%
|  | Key Lake – 83.33%
Mine type |  | Underground
Mining methods |  | Primary: raiseboring
|  | Secondary: blasthole stoping, boxhole boring
End product |  | Uranium concentrates
Certification |  | ISO 14001 certified
Estimated reserves |  | 234.9 million pounds (proven and probable), average grade U3O8: 10.94%
Estimated resources |  | 3.9 million pounds (measured and indicated), average grade U3O8: 3.77%
|  | 40.9 million pounds (inferred), average grade U3O8: 7.72%
Licensed capacity |  | Mine and mill: 25.0 million pounds per year
Licence term |  | Through October, 2023
Total production: 2000 to 2015 |  | 291.1 million pounds (McArthur River/Key Lake) (100% basis)
1983 to 2002 |  | 209.8 million pounds (Key Lake) (100% basis)
2015 production |  | 13.3 million pounds (19.1 million pounds on 100% basis)
2016 production outlook |  | 14.0 million pounds (20.0 million pounds on 100% basis)
Estimated decommissioning cost |  | $48 million – McArthur River (100% basis)
|  | $218 million – Key Lake (100% basis)

All values shown, including reserves and resources, represent our share only, unless indicated.

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 55

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 an underground 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. 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 and north areas.

The Canadian Nuclear Safety Commission (CNSC) has granted approval for the use of two secondary extraction methods: blasthole stoping and boxhole boring.

Our use of blasthole stoping as an ore extraction method has increased as a result of the significant productivity improvements we have achieved with this method. The amount of ore extracted from a single stope can be equivalent to four to eight raisebore holes, resulting in more efficient mining, less waste rock handling, less backfill placement and lower backfill dilution in the ore shipped to Key Lake.

We have used the approved mining methods to successfully extract over 290 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, although we now expect to mine a significant portion of the remaining reserves with blasthole stoping.

56 CAMECO CORPORATION

Blasthole stoping

Similar to raiseboring, blasthole stoping requires establishing drill access above the mineralization and extraction access below the mineralization. We begin each stope with a single raisebore hole (explained above). The stope is then formed by expanding the circumference of the raise by drilling longholes around the raisebore hole and blasting the ore. The blasted material funnels into the raisebore hole and drops to the extraction level below. The broken rock is collected on the lower level and removed by line-of-sight remote-controlled scoop trams, then transported to the grinding circuit. Once a stope is mined out, it is backfilled with concrete to maintain ground stability and allow the next stope and/or raise to be mined. This mining method has been used extensively in the mining industry, including uranium mining.

We continue to employ blasthole stoping only in areas where the longholes can be accurately drilled, and where stable stopes can be excavated without jeopardizing the integrity of the freezewall.

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.

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.

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.

2015 UPDATE

Production

Production from McArthur River/Key Lake was 19.1 million pounds; our share was 13.3 million pounds. This was 3% lower than our forecast for the year due to unplanned maintenance outages to repair the calciner at Key Lake. Annual production was unchanged from 2014.

Licensing and production capacity

In 2015, the CNSC approved our application to increase McArthur River’s licensed annual production to 25 million pounds (100% basis) to allow flexibility to match the approved Key Lake mill capacity. The licence conditions handbooks for these operations now allow both operations to produce up to 25 million pounds (100% basis) per year.

Key Lake extension and McArthur River production expansion

In support of our strategy to maintain the flexibility to respond to market conditions as they evolve, we continue to advance projects that are necessary to sustain and increase production when the market signals that additional production is needed.

MANAGEMENT’S DISCUSSION AND ANALYSIS 57

The Key Lake mill began operating in 1983 and we continue to upgrade circuits with new technology to simplify operations and improve environmental performance. The extension project involved increasing our tailings capacity and the mill’s nominal annual production rate to closely follow production from the McArthur River mine. As part of the mill upgrades, we continue to construct and commission a new calciner circuit, and expect to begin operating with the new calciner in 2016. The existing calciner circuit will remain in place until operational reliability of the new calciner is achieved. The calciner replacement project was planned in a way that temporarily allows us to use either calciner, which will help to mitigate risks to our production rate during the commissioning phase. In order to increase production at Key Lake, we also need to optimize and expand the solvent extraction and crystallization circuits in the mill (projects planned for 2017).

At McArthur River, we must continue to successfully transition into new mine areas through mine development and investment in support infrastructure. We plan to:

• |  | 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 freeze capacity and ventilation. In 2015, we continued to upgrade our electrical infrastructure on surface as part of our plan to address these future needs. We advanced groundworks to prepare for the next freeze plant, which is scheduled to begin freezing the south end of the orebody (zone 4) in 2017.

We also made changes in shaft 2 to increase air flow, resulting in a 15% to 20% improvement in ventilation capacity. The improved ventilation eliminates the need for a new ventilation shaft to support a higher production rate.

Tailings capacity

We 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.

PLANNING FOR THE FUTURE

Production

We plan to produce 20.0 million pounds in 2016; our share is 14.0 million pounds.

Expansion progress

As previously disclosed in our 2012 Technical Report, we plan to reach an annual capacity of 22 million pounds by 2018. The capital required to do so is shown in our 2016 capital spending plan, and in our outlook for investing activities in 2017 and 2018, beginning on page 38.

As we increase to 22 million pounds per year, we will optimize the capacity of both the Key Lake mill and McArthur River mine with a view to further increasing production to 25 million pounds per year (100% basis), as market conditions improve. Using this approach, we do not expect significant additional growth capital will be required to increase from annual production of 22 million pounds to an annual rate of 25 million pounds. We expect that this paced approach will allow us to extract maximum value from the operation as the market transitions.

Exploration

In 2015, underground drilling further delineated the zone A mineral resources. Underground definition drilling of zone B will be conducted in 2016 and 2017 to provide the information required for engineering work to develop more detailed mining plans.

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.

58 CAMECO CORPORATION

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 52 to 53.

MANAGEMENT’S DISCUSSION AND ANALYSIS 59

Uranium – operating properties

Cigar Lake

|  | 2015 Production (our share) 5.7M lbs 2016 Production Outlook (our share) 8.0M lbs1 Estimated Reserves (our share) 110.9M lbs Estimated Mine Life 2028 |  |

Cigar Lake is the world’s highest grade uranium mine, 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%
Mine type |  | Underground
Mining method |  | Jet boring system
End product |  | Uranium concentrates
Certification |  | ISO 14001 certified
Estimated reserves |  | 110.9 million pounds (proven and probable), average grade U3O8: 16.70%
Estimated resources |  | 1.6 million pounds (measured and indicated), average grade U3O8: 7.38% 51.6 million pounds (inferred), average grade U3O8: 16.43%
Licensed capacity |  | 18.0 million pounds per year (our share 9.0 million pounds per year)
Licence term |  | Through June, 2021
Total production: 2014 to 2015 |  | 11.8 million pounds (100% basis)
2015 production |  | 5.7 million pounds (11.3 million pounds on 100% basis)
2016 production outlook |  | 8.0 million pounds (16.0 million pounds on 100% basis)1
Estimated decommissioning cost |  | $49 million (100% basis)

1 | Our 2016 production plan is subject to regulatory approval for a production increase at the McClean Lake mill.

All | values shown, including reserves and resources, represent our share only, unless indicated.

BACKGROUND

Development

We began developing the Cigar Lake underground mine in 2005, but development was delayed due to water inflows. In October 2014, the McClean Lake mill produced first uranium concentrate from ore mined at the Cigar Lake operation. Commercial production was declared in May 2015.

Mining method and development techniques

Bulk freezing

The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. To prevent water from entering the mine, help stabilize weak rock formations, and meet our production schedule, the ore zone and surrounding ground in the area to be mined must meet specific ground freezing requirements before we begin jet boring.

60 CAMECO CORPORATION

During construction, development and remediation of the underground infrastructure, we employed a hybrid ground freezing approach using a combination of underground and surface freezing. The costs related to each technique are similar; however, there are significant advantages to freezing the ground from the surface. With surface freezing, less mine development is required, which results in less waste rock and greater ground stability, since freeze tunnels are not required between production tunnels. In addition, congestion is reduced and underground development for freeze infrastructure is no longer a critical path mine activity. Based on these advantages, we have elected to proceed exclusively using surface freezing to mine current reserves at Cigar Lake.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS 61

We have divided the orebody into production panels and at least three production panels need to be frozen at one time to achieve the full annual production rate of 18 million pounds. One JBS machine will be located in each frozen panel and the three JBS machines required are currently in operation. Due to limitations on the availability of high pressure water, two machines can be actively mining at any given time while the third is moving, setting up, or undergoing maintenance. Later in the mine plan, we may require a fourth JBS machine to sustain annual production of 18 million pounds.

Milling

All of Cigar Lake’s ore slurry is being 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 the capital costs for the modification and expansion.

2015 UPDATE

Production

Total packaged production from Cigar Lake was 11.3 million pounds U3O8; our share was 5.7 million pounds. The operation exceeded our forecast of 10 million pounds (100% basis) as a result of higher productivity and our intention to adjust annual production as necessary, based on our operating experience during rampup.

During the year, we:

• |  | completed commissioning of the equipment required to operate three JBS units at a production scale

• |  | brought on additional slurry haul trucks to ensure a sufficient quantity of ore slurry can be transported to the McClean Lake mill

• |  | completed final commissioning of underground processing circuits and updated our production rampup plan based on commissioning experience

• |  | modified mine and project plans to reflect our decision to exclusively freeze from surface

• |  | declared commercial production

Commercial production

Commercial production signals a transition in the accounting treatment for costs incurred at the mine. Cigar Lake met all of the criteria for commercial production, including cycle time and process specifications, in the second quarter of 2015. Therefore, effective May 1, 2015, we began charging all production costs, including depreciation, to inventory and subsequently recognizing them in cost of sales as the product is sold.

Underground development

As a result of our decision to exclusively use surface freezing going forward, and the resulting change in the mine plan, the bulk of the development and freeze drilling required for mining in 2016 is already complete. We are continuing to plan for future expansion of surface freezing infrastructure in late 2016.

McClean Lake mill update

Additional estimated expenditures of $50 million (100% basis, our share $25 million) are expected to be required at the McClean Lake mill in 2016, primarily to complete upgrades in the tailings neutralization area in support of the continued rampup to full production of 18 million pounds per year.

PLANNING FOR THE FUTURE

Production

In 2016, we expect to produce 16.0 million packaged pounds at Cigar Lake; our share is 8.0 million pounds.

62 CAMECO CORPORATION

In 2016, we also expect to:

• |  | extend the current surface freeze pad and advance planning for freeze plant infrastructure expansion to support future production

• |  | advance underground development according to the new mine plan and backfill drifts no longer required for underground freezing operations

• |  | continue ramping up towards the planned full annual production rate of 18 million pounds (100% basis) in 2017

Exploration

We are planning to conduct delineation drilling from surface to confirm and upgrade resources contained in the western portion of the deposit. Approximately 65,000 metres of diamond drilling is planned over a three-year period, starting in 2016, in order to complete a detailed geological and geotechnical interpretation, a resource estimate, and a technical study for the western portion of the deposit.

Rampup schedule

In 2017, we expect to reach full annual production of 18 million pounds (100% basis, 9 million pounds our share).

The McClean Lake mill’s operating licence currently has an annual production limit of 13 million pounds. AREVA has submitted an application to the CNSC to increase the mill’s licensed annual production limit; our 2016 and 2017 production outlook for Cigar Lake is therefore subject to AREVA securing the regulatory approvals necessary to increase mill production.

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, regulatory approvals, 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.

Limited mining experience of the deposit

Although we have now successfully mined a number of cavities, these 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.

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 in 2017 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.

Mill licence increase approval

The McClean Lake mill’s current annual operating licence is limited to 13 million pounds. AREVA has submitted an application to the CNSC to increase the mill’s licensed annual production limit to 24 million pounds. There is a risk to our 2016 production plan, and to our plan to achieve the full production rate of 18 million pounds per year in 2017, if AREVA is unable to secure the regulatory approvals necessary to increase mill production.

MANAGEMENT’S DISCUSSION AND ANALYSIS 63

Labour relations

The current collective agreement between AREVA and unionized employees at the McClean Lake operation expires in May 2016. There is risk to our 2016 and 2017 production outlook for Cigar Lake if AREVA is unable to reach an agreement and there is a labour dispute.

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 52 to 53.

64 CAMECO CORPORATION

Uranium – operating properties

Inkai

|  | 2015 Production (our share) 3.4M lbs 2016 Production Outlook (our share) 3.0M lbs Estimated Reserves (our share) 43.1M 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%
Mine type |  | In situ recovery (ISR)
End product |  | Uranium concentrates
Certifications |  | BSI OHSAS 18001 ISO 14001 certified
Estimated reserves |  | 43.1 million pounds (proven and probable), average grade U3O8: 0.07%
Estimated resources |  | 30.3 million pounds (indicated), average grade U3O8: 0.08% 144.3 million pounds (inferred), average grade U3O8: 0.05%
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: 2009 to 2015 |  | 31.8 million pounds (100% basis)
2015 production |  | 3.4 million pounds (5.8 million pounds on 100% basis)
2016 production outlook |  | 3.0 million pounds (5.2 million pounds on 100% basis)
Estimated decommissioning cost (100% basis) |  | $9 million (US) (100% basis)

All values shown, including reserves and resources, represent our share only, unless indicated.

2015 UPDATE

Production

Total production from Inkai was 5.8 million pounds; our share was 3.4 million pounds. Production was 17% higher than our production in 2014. During 2015, the subsoil use law in Kazakhstan was amended to allow producers to produce within 20% (above or below) their licensed capacity in a year. As a result, Inkai produced 5.8 million pounds in 2015, 11% higher than its licensed capacity. The increase in production was the result of a higher head grade and an increase in wellfield development efficiency compared to 2014.

Project funding

As of December 31, 2015, Inkai had fully repaid the outstanding loan under our agreement to fund its project development costs related to blocks 1 and 2. In 2015, Inkai paid the remaining $0.8 million (US) in interest on the loan and repaid $55 million (US) of principal.

MANAGEMENT’S DISCUSSION AND ANALYSIS 65

We are currently advancing funds for Inkai’s work on block 3 and, as of December 31, 2015, the principal amounted to $148 million (US). Under the loan agreement, Inkai is to repay Cameco from the net sales proceeds from the sale of production from block 3.

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 Co-operation 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 2015, Inkai completed construction of the test leach facility and began pilot production from test wellfields, as well as advancing work on a preliminary appraisal of the mineral potential of block 3 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 2016; our share is 3.0 million pounds. We expect to maintain production at this level until the potential growth plans are finalized with Kazatomprom.

Block 3 exploration

In 2016, Inkai expects to continue with pilot production from the test leach facility and to continue working on a final appraisal of the mineral potential according to Kazakhstan standards.

MANAGING OUR RISKS

Block 3 licence extension

The block 3 test leach facility is now operational and state commissioning of the test wellfields was accomplished during 2015. Our application for an extension of the block 3 evaluation period is still pending final approval from the Ministry of Energy of the Republic of Kazakhstan. Inkai continues working on the final appraisal of the mineral potential of block 3 according to Kazakhstan standards. 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.

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

66 CAMECO CORPORATION

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 52 to 53.

MANAGEMENT’S DISCUSSION AND ANALYSIS 67

Uranium – operating properties

Rabbit Lake

|  | 2015 Production 4.2M lbs 2016 Production Outlook 3.6M lbs Estimated Reserves 11.9M lbs |  |

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 |  | 11.9 million pounds (proven and probable), average grade U3O8: 0.59%
Estimated resources |  | 26.7 million pounds (indicated), average grade U3O8: 0.86%
|  | 33.7 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 2015 |  | 202.2 million pounds
2015 production |  | 4.2 million pounds
2016 production outlook |  | 3.6 million pounds
Estimated decommissioning cost |  | $203 million

2015 UPDATE

Production

Production this year was unchanged from our 2014 production as a result of planned timing of production stopes, coupled with slightly improved ore grades.

Development and production continued at the Eagle Point mine. At the mill, we continued to improve the efficiency of the mill operation schedule.

Temporary mining restrictions

On December 17, 2015, we announced that underground mining activities at Eagle Point were being restricted due to a rock fall in an inactive area of the mine. As a precautionary measure, non-essential personnel were removed from the mine while the condition of the affected area was evaluated. Mine production was suspended, although milling of previously mined and transported ore continued through to year end.

The assessment determined that repairs were necessary to support the ground in the affected area of the mine. The repairs were completed, along with some further assessment of stability in other areas of the mine. The mine was reopened and normal operations resumed on February 3, 2016.

68 CAMECO CORPORATION

Impairment

During the fourth quarter of 2015, we recognized a $210 million impairment charge related to our Rabbit Lake operation. The impairment was due to increased uncertainty around future production sources for the Rabbit Lake mill as a result of the ongoing economic conditions. The amount of the charge was determined as the excess of carrying value over the recoverable amount. The recoverable amount of the mill was determined to be $69 million.

PLANNING FOR THE FUTURE

Production

We expect to produce 3.6 million pounds in 2016. The decrease compared to 2015 is the result of the restriction of mining activities at the end of 2015, which extended into 2016.

Tailings capacity

Under our current licence, we expect to have sufficient tailings capacity to support milling of Eagle Point ore until about late 2017, based upon expected ore tonnage, milling rates and tailings properties.

Our plan for fully utilizing the available tailings capacity of the Rabbit Lake In-Pit Tailings Management facility requires regulatory approval in 2016 for which we have submitted the required applications. With these regulatory approvals and after we complete the necessary work on the existing pit, we expect to then have sufficient tailings capacity to support milling of Eagle Point ore until at least 2021 based upon expected ore tonnage, milling rates, and tailings properties.

Exploration

We plan to continue our underground drilling reserve replacement program in areas of interest north and northeast of the current mine workings in 2016. The drilling will be carried out from underground locations.

Reclamation

As part of our multi-year site-wide reclamation plan, we spent over $0.7 million in 2015 to reclaim facilities that are no longer in use and plan to spend over $0.5 million in 2016.

MANAGING OUR RISKS

We manage the risks listed on pages 52 to 53.

MANAGEMENT’S DISCUSSION AND ANALYSIS 69

Uranium – operating properties

Smith Ranch-Highland & Satellite Facilities

|  | 2015 Production 1.4M lbs 2016 Production Outlook 1.2M lbs Estimated Reserves 8.0M lbs |  |

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: |  | 6.2 million pounds (proven and probable), average grade U3O8: 0.09%
| North Butte-Brown Ranch: |  | 1.8 million pounds (proven and probable), average grade U3O8: 0.08%
Estimated resources |  | Smith Ranch-Highland: |  | 19.8 million pounds (measured and indicated), average grade U3O8: 0.06%
|  |  |  | 7.7 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 2015 |  | 21.8 million pounds
2015 production |  |  |  | 1.4 million pounds
2016 production outlook |  |  |  | 1.2 million pounds
Estimated decommissioning cost |  | Smith Ranch-Highland: $206 million (US), North Butte: $22 million (US)

2015 UPDATE

Production

We met our forecast for the year although, as planned, production was 33% lower than in 2014, with new mine units and the North Butte satellite contributing to production at Smith Ranch-Highland in 2015.

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 2016, we expect to produce 1.2 million pounds. The continued 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 52 to 53.

70 CAMECO CORPORATION

Uranium – operating properties

Crow Butte

|  | 2015 Production 0.4M lbs 2016 Production Outlook 0.2M lbs Estimated Reserves 0.7M lbs |  |

Crow Butte was discovered in 1980 and began production in 1991.

Location |  | Nebraska, US
Ownership |  | 100%
End product |  | Uranium concentrates
ISO certification |  | ISO 14001 certified
Estimated reserves |  | 0.7 million pounds (proven), average grade U3O8: 0.08%
Estimated resources |  | 15.2 million pounds (measured and indicated), average grade U3O8: 0.25%
|  | 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 2015 |  | 10.1 million pounds
2015 production |  | 0.4 million pounds
2016 production outlook |  | 0.2 million pounds
Estimated decommissioning cost |  | $46 million (US)

2015 UPDATE

Production

Production this year was higher than forecast, but 33% lower than 2014 due to declining head grade.

PLANNING FOR THE FUTURE

Production

In 2016, we expect to produce 0.2 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 52 to 53.

MANAGEMENT’S DISCUSSION AND ANALYSIS 71

Uranium – projects under evaluation

Work on our projects under evaluation has been scaled back and will continue at a pace aligned with market signals.

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.

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.

Kintyre

Location |  | Western Australia
Ownership |  | 70%
End product |  | Uranium concentrates
Potential mine type |  | Open pit
Estimated resources (our share) |  | 37.5 million pounds (indicated), average grade U3O8: 0.62%
|  | 4.2 million pounds (inferred), average grade U3O8: 0.53%

BACKGROUND

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

2015 PROJECT UPDATES

We believe that we have some of the best undeveloped uranium projects in the world. However, in the current market environment our primary focus is on uranium production and our tier-one assets. We continue to await a signal from the market that additional production is needed prior to making any new development decisions.

This year, on our projects under evaluation we:

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

• |  | at Kintyre and at other nearby regional exploration projects, we carried out further exploration work to test for potential satellite deposits. There were no significant results.

• |  | we received environmental approval for Kintyre and continued to advance Yeelirrie through the environmental assessment process

72 CAMECO CORPORATION

PLANNING FOR THE FUTURE

2016 Planned activity

At Millennium, no work is planned, as regulatory activity related to our final environmental impact statement continues to be on hold. Further progress towards a development decision is not expected until market conditions improve.

At Yeelirrie, we plan to further advance the project through the environmental assessment process and continue working on proposals required under the Yeelirrie State Agreement. Under the State Agreement, the Western Australian Government provides a framework for the approval and development of the project. Detailed proposals for the development of a mine and related infrastructure must be submitted to the government for approval by June 20, 2018, in order to retain the tenements and titles for the Yeelirrie project.

At Kintyre and other nearby regional exploration projects, we expect to continue with further exploration work to test for potential satellite deposits.

MANAGING THE RISKS

For all of our projects under evaluation, we manage the risks listed on pages 52 to 53.

MANAGEMENT’S DISCUSSION AND ANALYSIS 73

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 1.6 million hectares (3.9 million acres). In northern Saskatchewan alone, we have direct interests in 600,000 hectares (1.5 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 2015, we continued our exploration strategy of focusing on the most prospective projects in our portfolio. Exploration is key to ensuring our long-term growth.

2015 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 $2 million on four brownfield exploration projects, $4 million on our projects under evaluation in Australia, and $2 million at Inkai and 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 2016, we plan to spend approximately $5 million on brownfield exploration and $4 million on projects under evaluation.

Regional exploration

We plan to spend about $36 million on 24 projects in Canada and Australia, the majority of which are at drill target stage. Among the larger expenditures planned is $7 million on the Read Lake project, which is adjacent to McArthur River in Saskatchewan. We will also spend a total of $2 million at Inkai and in the US.

74 CAMECO CORPORATION

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 in the strategy section, starting on page 14. Currently, given the conditions in the uranium market, and our extensive portfolio of reserves and resources, our focus is on our tier-one assets. We expect that these assets will allow us to meet rising uranium demand with increased production from our best margin operations, and will help to mitigate risk in the event of prolonged uncertainty.

MANAGEMENT’S DISCUSSION AND ANALYSIS 75

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 Licence renewal in Feb, 2022 |  |

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 |  | 18.0 million kgU as UO3 per year, approved to 24.0 million subject to completion of certain equipment upgrades (advancement depends on market conditions)
Licence term |  | Through February, 2022
Estimated decommissioning cost |  | $39 million

76 CAMECO CORPORATION

Port Hope Conversion Services

|  | Licensed Capacity 12.5M kgU of UF6 2.8M kgU of UO2 Licence renewal in Feb, 2017 |  |

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 (an updated estimate is currently under regulatory review)

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

2015 UPDATE

Production

Fuel services produced 9.7 million kgU, 16% lower than 2014. This was a result of our decision to decrease production in response to weak market conditions and the termination of our toll milling agreement with SFL in 2014.

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

The Vision in Motion project is currently in the feasibility stage and will continue with the CNSC licensing process in 2016, which is required to advance the project.

Labour relations

Approximately 100 unionized employees at Cameco Fuel Manufacturing Inc.’s operations in Port Hope and Cobourg, Ontario accepted a new collective bargaining agreement in the second quarter of 2015. The employees, represented by the United Steelworkers local 14193, agreed to a three-year contract that includes a 7% wage increase over the term of the agreement. The previous contract expired on June 1, 2015.

MANAGEMENT’S DISCUSSION AND ANALYSIS 77

PLANNING FOR THE FUTURE

Production

We have decreased our production target for 2016 to between 8 million and 9 million kgU in response to the continued weak market conditions.

Labour relations

The current collective bargaining agreement for our unionized employees at the Port Hope conversion facility expires on June 30, 2016. We will commence the bargaining process in early 2016.

Regulatory

The current operating licence for the Port Hope conversion facility expires in February 2017. The CNSC relicensing process will take place in 2016.

MANAGING OUR RISKS

We also manage the risks listed on pages 52 to 53.

78 CAMECO CORPORATION

NUKEM GmbH

Offices |  | Alzenau, Germany (Headquarters, NUKEM GmbH)
|  | Connecticut, US (Subsidiary, NUKEM Inc.)
Ownership |  | 100%
Activity |  | Trading of uranium and uranium-related products
2015 sales1 |  | 10.7 million pounds U3O8
2016 forecast sales |  | 9 to 10 million pounds U3O8

1 | Includes sales of 0.9 million pounds and revenue of $19.3 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 nonspeculative 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 79

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, and 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/Key Lake, 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, constant dollar average uranium prices of $57 to $59 (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%).

80 CAMECO CORPORATION

Changes this year

Our share of proven and probable mineral reserves decreased from 429 million pounds U3O8 at the end of 2014, to 410 million pounds at the end of 2015. The change was primarily the result of production, which removed 30 million pounds from our mineral inventory. However, the decrease was partially offset due to the replacement of raiseboring with blasthole stoping in some areas of McArthur River, as well as additional information from drilling surface freeze holes at Cigar Lake, which both resulted in higher reserves when the related probable reserves were converted to proven reserves.

Measured and indicated mineral resources decreased from 379 million pounds U3O8 at the end of 2014, to 377 million pounds at the end of 2015. Our share of inferred mineral resources is 380 million pounds U3O8, an increase of 68 million pounds from the end of 2014. The variance in mineral resources was mainly the result of:

• |  | the addition of 4.5 million pounds U3O8 to indicated resources and 8 million pounds to inferred resources at Rabbit Lake from additional drilling, and from a revision to the equivalent grade formula

• |  | first time reporting for the Fox Lake deposit, on the Read Lake property near McArthur River, adding 53 million pounds U3O8 to inferred resources

• |  | the addition of 13 million pounds U3O8 of inferred resources from the Gryphon deposit on the Wheeler River property

• |  | a revised pit shell defining the mineral resources at Kintyre

Qualified persons

The technical and scientific information discussed in this MD&A for our material properties (McArthur River/Key Lake, Cigar Lake and Inkai) 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

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

CIGAR LAKE

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

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

• |  | Scott Bishop, manager, 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

MANAGEMENT’S DISCUSSION AND ANALYSIS 81

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.

82 CAMECO CORPORATION

Mineral reserves

As at December 31, 2015 (100% basis – only the shaded column shows our share)

PROVEN AND PROBABLE

(tonnes in thousands; pounds in millions)

|  |  |  | PROVEN |  |  | PROBABLE |  |  | TOTAL MINERAL RESERVES |  |  | OUR RESERVES 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 |  |  | 1,195.3 |  |  |  | 9.62 |  |  |  | 253.5 |  |  |  | 199.8 |  |  |  | 18.84 |  |  |  | 83.0 |  |  |  | 1,395.1 |  |  |  | 10.94 |  |  |  | 336.5 |  |  |  | 234.9 |  |  |  | 98.7 |
Cigar Lake |  | UG |  |  | 226.1 |  |  |  | 21.93 |  |  |  | 109.3 |  |  |  | 375.7 |  |  |  | 13.55 |  |  |  | 112.3 |  |  |  | 601.8 |  |  |  | 16.70 |  |  |  | 221.6 |  |  |  | 110.9 |  |  |  | 98.5 |
Rabbit Lake |  | UG |  |  | 10.6 |  |  |  | 0.34 |  |  |  | 0.1 |  |  |  | 902.9 |  |  |  | 0.59 |  |  |  | 11.8 |  |  |  | 913.5 |  |  |  | 0.59 |  |  |  | 11.9 |  |  |  | 11.9 |  |  |  | 97.0 |
Key Lake |  | OP |  |  | 61.1 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 61.1 |  |  |  | 0.52 |  |  |  | 0.7 |  |  |  | 0.6 |  |  |  | 98.7 |
Inkai |  | ISR |  |  | 1,139.5 |  |  |  | 0.08 |  |  |  | 2.1 |  |  |  | 50,476.4 |  |  |  | 0.07 |  |  |  | 72.9 |  |  |  | 51,615.9 |  |  |  | 0.07 |  |  |  | 75.0 |  |  |  | 43.1 |  |  |  | 85.0 |
Smith Ranch-Highland |  | ISR |  |  | 1,127.8 |  |  |  | 0.10 |  |  |  | 2.5 |  |  |  | 1,871.0 |  |  |  | 0.09 |  |  |  | 3.8 |  |  |  | 2,998.8 |  |  |  | 0.09 |  |  |  | 6.2 |  |  |  | 6.2 |  |  |  | 80.0 |
North Butte-Brown Ranch |  | ISR |  |  | 644.2 |  |  |  | 0.08 |  |  |  | 1.2 |  |  |  | 373.8 |  |  |  | 0.08 |  |  |  | 0.7 |  |  |  | 1,018.0 |  |  |  | 0.08 |  |  |  | 1.8 |  |  |  | 1.8 |  |  |  | 60.0 |
Crow Butte |  | ISR |  |  | 412.5 |  |  |  | 0.08 |  |  |  | 0.7 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 412.5 |  |  |  | 0.08 |  |  |  | 0.7 |  |  |  | 0.7 |  |  |  | 85.0 |
Total |  |  |  |  | 4,817.2 |  |  |  | — |  |  |  | 370.1 |  |  |  | 54,199.5 |  |  |  | — |  |  |  | 284.4 |  |  |  | 59,016.7 |  |  |  | — |  |  |  | 654.5 |  |  |  | 410.2 |  |  |  | — |

(UG – underground, OP – open pit, ISR – in situ recovery, totals may not add up due to rounding.

Note that the estimates in the above table:

• |  | use constant dollar average uranium prices of $57 to $59 (US)/lb U3O8

• |  | are based on an average exchange rate of $1.00 US=$1.15 to $1.25 Cdn

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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 83

Mineral resources

As at December 31, 2015 (100% – only the shaded columns show our share)

MEASURED, INDICATED AND INFERRED

(tonnes in thousands; pounds in millions)

|  | MEASURED RESOURCES (M) |  |  | INDICATED RESOURCES (I) |  |  |  |  |  | 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) |  |  | TOTAL M+I CONTENT (LBS U3O8) |  |  |  | TONNES |  |  | GRADE % U3O8 |  |  | CONTENT (LBS U3O8) |  |
McArthur River |  |  | 62.0 |  |  |  | 3.83 |  |  |  | 5.2 |  |  |  | 4.8 |  |  |  | 3.02 |  |  |  | 0.3 |  |  |  | 5.6 |  |  |  | 3.9 |  |  |  | 344.2 |  |  |  | 7.72 |  |  |  | 58.6 |  |  |  | 40.9 |
Cigar Lake |  |  | 2.7 |  |  |  | 6.06 |  |  |  | 0.4 |  |  |  | 17.5 |  |  |  | 7.59 |  |  |  | 2.9 |  |  |  | 3.3 |  |  |  | 1.6 |  |  |  | 284.7 |  |  |  | 16.43 |  |  |  | 103.1 |  |  |  | 51.6 |
Rabbit Lake |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,402.7 |  |  |  | 0.86 |  |  |  | 26.7 |  |  |  | 26.7 |  |  |  | 26.7 |  |  |  | 2,645.6 |  |  |  | 0.58 |  |  |  | 33.7 |  |  |  | 33.7 |
Millennium |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 1,442.6 |  |  |  | 2.39 |  |  |  | 75.9 |  |  |  | 75.9 |  |  |  | 53.0 |  |  |  | 412.4 |  |  |  | 3.19 |  |  |  | 29.0 |  |  |  | 20.2 |
Wheeler River |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 166.4 |  |  |  | 19.13 |  |  |  | 70.2 |  |  |  | 70.2 |  |  |  | 21.1 |  |  |  | 842.5 |  |  |  | 2.38 |  |  |  | 44.1 |  |  |  | 13.2 |
Fox Lake |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 386.7 |  |  |  | 7.99 |  |  |  | 68.1 |  |  |  | 53.3 |
Tamarack |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 183.8 |  |  |  | 4.42 |  |  |  | 17.9 |  |  |  | 17.9 |  |  |  | 10.3 |  |  |  | 45.6 |  |  |  | 1.02 |  |  |  | 1.0 |  |  |  | 0.6 |
Kintyre |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 3,897.7 |  |  |  | 0.62 |  |  |  | 53.5 |  |  |  | 53.5 |  |  |  | 37.5 |  |  |  | 517.1 |  |  |  | 0.53 |  |  |  | 6.0 |  |  |  | 4.2 |
Yeelirrie |  |  | 24,013.5 |  |  |  | 0.17 |  |  |  | 92.4 |  |  |  | 12,626.5 |  |  |  | 0.13 |  |  |  | 34.9 |  |  |  | 127.3 |  |  |  | 127.3 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Inkai |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 31,366.1 |  |  |  | 0.08 |  |  |  | 52.6 |  |  |  | 52.6 |  |  |  | 30.3 |  |  |  | 250,958.6 |  |  |  | 0.05 |  |  |  | 251.0 |  |  |  | 144.3 |
Smith Ranch-Highland |  |  | 1,241.9 |  |  |  | 0.11 |  |  |  | 2.9 |  |  |  | 14,338.1 |  |  |  | 0.05 |  |  |  | 16.9 |  |  |  | 19.8 |  |  |  | 19.8 |  |  |  | 6,861.0 |  |  |  | 0.05 |  |  |  | 7.7 |  |  |  | 7.7 |
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 |  |  | 1,418.2 |  |  |  | 0.21 |  |  |  | 6.6 |  |  |  | 1,354.9 |  |  |  | 0.29 |  |  |  | 8.6 |  |  |  | 15.2 |  |  |  | 15.2 |  |  |  | 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 |  |  | 27,747.4 |  |  |  | — |  |  |  | 109.9 |  |  |  | 79,811.2 |  |  |  | — |  |  |  | 388.7 |  |  |  | 498.5 |  |  |  | 377.2 |  |  |  | 268,599.9 |  |  |  | — |  |  |  | 613.0 |  |  |  | 380.5 |

Totals may not add up due to rounding.

Note that mineral resources:

• |  | do not include amounts that have been identified as mineral reserves

• |  | do not have demonstrated economic viability

84 CAMECO CORPORATION

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 17 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS 85

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, 2015, 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, 2015. We have not made any change to our internal control over financial reporting during the 2015 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, 2015, and have not been applied in preparing these consolidated financial statements. Cameco does not intend to early adopt any of the following amendments to existing standards and does not expect the amendments to have a material impact on the financial statements, unless otherwise noted.

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

86 CAMECO CORPORATION

IFRS 9, Financial Instruments (IFRS 9) – In July 2014, the IASB issued IFRS 9. IFRS 9 replaces the existing guidance in IAS 39, Financial Instruments: Recognition and Measurement (IAS 39). IFRS 9 includes revised guidance on the classification and measurement of financial assets, a new expected credit loss model for calculating impairment on financial assets and new hedge accounting requirements. It also carries forward, from IAS 39, guidance on recognition and derecognition of financial instruments.

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

IFRS 16, Leases (IFRS 16) – In January 2016, the IASB issued IFRS 16 which is effective for periods beginning on or after January 1, 2019, with early adoption permitted. IFRS 16 eliminates the current dual model for lessees, which distinguishes between on-balance sheet finance leases and off-balance sheet operating leases. Instead, there is a single, on-balance sheet accounting model that is similar to current finance lease accounting. The extent of the impact of adoption of IFRS 16 has not yet been determined.

MANAGEMENT’S DISCUSSION AND ANALYSIS 87