EX-99.1 2 d685238dex991.htm EX-99.1

Exhibit 99.1

Cameco Corporation

2013 Annual information form

February 27, 2014

Contents

Important information about this document |  |  | 1 |
About Cameco |  |  | 4 |
Operations and development projects |  |  | 16 |
Uranium – operating properties |  |  | 17 |
Uranium – development project |  |  | 47 |
Uranium – projects under evaluation |  |  | 61 |
Fuel services – refining |  |  | 65 |
Fuel services – conversion and fuel manufacturing |  |  | 66 |
NUKEM GmbH |  |  | 69 |
Electricity |  |  | 70 |
Mineral reserves and resources |  |  | 75 |
Sustainable development |  |  | 83 |
The regulatory environment |  |  | 93 |
Risks that can affect our business |  |  | 101 |
Legal proceedings |  |  | 122 |
Investor information |  |  | 123 |
Governance |  |  | 129 |
Appendix A |  |  | 134 |

- i -

Important information about this document

This annual information form (AIF) provides important information about Cameco Corporation. It describes our history, our markets, our operations and development projects, our mineral reserves and resources, sustainability, our regulatory environment, the risks we face in our business and the market for our shares, among other things.

It also incorporates by reference:

• |  | our management’s discussion and analysis (MD&A) for the year ended December 31, 2013 (2013 MD&A), which is available on SEDAR (sedar.com) and on EDGAR (sec.gov) as an exhibit to our Form 40-F

• |  | our audited consolidated financial statements for the year ended December 31, 2013 (2013 financial statements) which is also available on SEDAR and on EDGAR as an exhibit to our Form 40-F.

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

We have prepared this document to meet the requirements of Canadian securities laws, which are different from what US securities laws require.

Reporting currency and financial information

Unless we have specified otherwise, all dollar amounts are in Canadian dollars. Any references to $(US) mean United States (US) dollars.

The financial information in this AIF has been presented in accordance with International Financial Reporting Standards (IFRS).

Caution about forward-looking information

Our AIF and the documents incorporated by reference include statements and information about our expectations for the future. When we discuss our strategy, plans and future financial and operating performance, or other things that have not yet taken place, we are making statements considered to be forward-looking information or forward-looking statements under Canadian and US securities laws. We refer to them in this AIF as forward-looking information.

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

• |  | It typically includes words and phrases about the future, such as believe, estimate, anticipate, expect, plan, intend, predict, goal, target, forecast, project, scheduled, potential, strategy and proposed (see examples on page 2).

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

• |  | Actual results and events may be significantly different from what we currently expect, because of the risks associated with our business. We list a number of these material risks below. We recommend you also review other parts of this document, including Risks that can affect our business starting on page 101, and our 2013 MD&A, which include a discussion of other material risks that could cause our actual results to differ from current expectations.

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

2013 ANNUAL INFORMATION FORM Page 1

Examples of forward-looking information in this AIF

• |  | our expectations about 2014 and future global uranium supply, consumption, demand, number of operable reactors and nuclear generating capacity, including the discussion under the heading The nuclear energy industry today

• |  | the discussion of our expectations relating to our tax dispute with Canada Revenue Agency (CRA) including our estimate of the amount and timing of expected cash taxes and transfer pricing penalties payable to CRA

• |  | future tax payments and rates

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

• |  | our expectation that we will begin mining in the first quarter of 2014 at Cigar Lake with AREVA’s McClean Lake mill processing the first ore at the end of the second quarter of 2014

• |  | our mineral reserve and resource estimates

Material risks

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

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

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

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

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

• |  | we are subject to litigation or arbitration that has an adverse outcome, including lack of success in our 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 in a developing country where we operate

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

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

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

• |  | our uranium and conversion suppliers fail to fulfill delivery commitments

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

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

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

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

2013 ANNUAL INFORMATION FORM Page 2

Material assumptions

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

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

• |  | our expected production levels and production costs

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

• |  | our expectations regarding spot prices and realized prices for uranium

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

• |  | our expectations about the outcome of the 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 Cigar Lake development, mining and production plans succeed, including the additional jet boring unit system is acquired on schedule, the jet boring mining method works as anticipated, and the deposit freezes as planned

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

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

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

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

• |  | our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, social or political activism, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, labour shortages, labour relations issues (including an ability to renew agreements with unionized employees at McArthur River and Key Lake), strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failures, lack of tailings capacity, transportation disruptions or accidents or other development or operating risks

2013 ANNUAL INFORMATION FORM Page 3

About Cameco

Our head office is in Saskatoon, Saskatchewan. We are one of the world’s largest uranium producers, with uranium assets on three continents. Nuclear energy plants around the world use our uranium products to generate one of the cleanest sources of electricity available today.

Strategy

Our strategy remains 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. You can find more information about our strategy in our 2013 MD&A.

Cameco Corporation

2121 – 11th Street West

Saskatoon, Saskatchewan

Canada S7M 1J3

Telephone: 306.956.6200

This is our head office, registered office and principal place of business.

We are publicly listed on the Toronto and New York stock exchanges, and had a total of 3,873 employees at December 31, 2013, not including BPLP.

Business segments

URANIUM

We are one of the world’s largest uranium producers, and in 2013 accounted for about 15% of the world’s production. We have controlling ownership of the world’s largest high-grade reserves, with ore grades up to 100 times the world average, and low-cost operations.

Operating properties

• |  | McArthur River and Key Lake, Saskatchewan

• |  | Rabbit Lake, Saskatchewan

• |  | Smith Ranch-Highland, Wyoming

• |  | Crow Butte, Nebraska

• |  | Inkai, Kazakhstan

Product

• |  | uranium concentrates (U3O8)

Development project

• |  | Cigar Lake, Saskatchewan

Mineral reserves and resources

Mineral reserves

• |  | approximately 443 million pounds proven and probable

Mineral resources

• |  | approximately 391 million pounds measured and indicated

• |  | approximately 289 million pounds inferred

Projects under evaluation

• |  | Inkai blocks 1 and 2 production increase, Kazakhstan

• |  | Inkai block 3, Kazakhstan

• |  | Millennium, Saskatchewan

• |  | Yeelirrie, Australia

• |  | Kintyre, Australia

Global exploration

• |  | focused on four continents

• |  | approximately 2.0 million hectares of land

2013 ANNUAL INFORMATION FORM Page 4

FUEL SERVICES

We are an integrated uranium fuel supplier, offering refining, conversion and fuel manufacturing services.

Products

• |  | uranium trioxide (UO3)

• |  | uranium hexafluoride (UF6) (control about 25% of world conversion capacity)

• |  | uranium dioxide (UO2)

• |  | fuel bundles, reactor components and monitoring equipment used by CANDU reactors

Operations

• |  | Blind River refinery, Ontario (refines uranium concentrates to UO3)

• |  | Port Hope conversion facility, Ontario (converts UO3 to UF6 or UO2)

• |  | Cameco Fuel Manufacturing Inc. (CFM), Ontario (manufactures fuel bundles and reactor components)

• |  | a toll conversion agreement with Springfields Fuels Ltd. (SFL), Lancashire, United Kingdom (UK) (to convert UO3 to UF6) – expires in 2016

NUKEM

Our ownership of NUKEM GmbH (NUKEM) provides us with access to one of the world’s leading traders of uranium and uranium-related products.

Activity

• |  | physical trading uranium concentrates, conversion and enrichment services through back-to-back purchase and sales transactions

• |  | recovery of natural and enriched non-standard uranium from western facilities and other sources

ELECTRICITY

We currently generate clean electricity through our 31.6% interest in the Bruce Power Limited Partnership (BPLP), which operates four nuclear reactors at the Bruce B generating station in southern Ontario. We have entered into an agreement to sell our interest in BPLP which is described in greater detail on page 71.

Capacity

• |  | 3,260 megawatts (MW) (100% basis) (about 15% of Ontario’s electricity)

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

• |  | uranium concentrates

• |  | conversion services

• |  | fuel fabrication services

For information about our revenue and gross profit by business segment for the years ended December 31, 2013 and 2012, see our 2013 MD&A as follows:

• |  | uranium – page 41

• |  | fuel services – page 44

• |  | electricity – page 46.

2013 ANNUAL INFORMATION FORM Page 5

Other fuel cycle investments

ENRICHMENT

We continue to explore innovative areas like laser enrichment technology to broaden our fuel cycle participation and help us serve our customers more effectively. Uranium enrichment is the second largest value component, after uranium, in a typical light water reactor fuel bundle. Having operational control of both uranium production and enrichment facilities would offer operational synergies that could significantly enhance profit margins.

The enrichment market has the same customer base as the uranium market, and most of the world’s commercial nuclear reactors need enriched uranium.

Investment

• |  | We have a 24% interest in Global Laser Enrichment (GLE) in North Carolina, with General Electric (51%) and Hitachi Ltd. (25%). GLE is testing a third-generation technology that, if successful, will use lasers to commercially enrich uranium.

2013 ANNUAL INFORMATION FORM Page 6

The nuclear fuel cycle

Our operations and investments span the nuclear fuel cycle, from exploration to fuel manufacturing.

1 | Mining

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

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

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

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

1 | Milling

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

2 | Refining

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

3 | Conversion

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

4 | Enrichment

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

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

5 | Fuel manufacturing

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

6 | Generation

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

Spent fuel management

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

2013 ANNUAL INFORMATION FORM Page 7

Major developments

2011 |  | 2012 |  | 2013 |  | 2014
January • We begin to freeze the ground around shaft 2 at Cigar Lake. March • We restart freezing the orebody from underground at Cigar Lake. April • Inkai receives approval to increase annual production from blocks 1 and 2 to 3.9 million pounds (100% basis). May • We resume the sinking of shaft 2 at Cigar Lake. July • We receive regulatory approval of our Cigar Lake mine plan. August • We enter into a memorandum of agreement with our partner, JSC NAC KazAtomProm, to increase annual uranium production at Inkai from 3.9 million pounds to 5.2 million pounds (100% basis). November • We cancel our $100 million bank credit facility that expires on February 4, 2012. • Our $500 million bank credit facility is increased to $1.25 billion. It expires in November 2017. December • We begin freezing the Cigar Lake orebody from the surface. Agreements are signed with the owners of the Cigar Lake project and the McClean Lake JEB mill to process all Cigar Lake ore at McClean Lake. |  | March • We enter into an agreement with AREVA Resources Canada Inc. (AREVA) to acquire its 27.94% interest in the Millennium project. May • We enter into an agreement with Advent International to purchase NUKEM, one of the world’s leading traders and brokers of nuclear fuel products and services. The purchase closes in January 2013. June • We complete the purchase of AREVA’s 27.94% interest in the Millennium project and thereby acquire majority ownership. July • We enter into a three-year collective agreement with about 120 unionized employees at our fuel manufacturing operations in Port Hope and Cobourg, Ontario. August • We enter into an agreement to acquire the Yeelirrie uranium project in Western Australia from BHP Billiton Yeelirrie Development Company Pty Ltd. September • The US Nuclear Regulatory Commission approved GLE’s application for a commercial facility construction and operating licence. October • Our Board of Directors approves a memorandum of agreement with KazAtomProm setting out the framework to increase annual production at Inkai to 10.4 million pounds (100% basis), to extend the term of Inkai’s resource use contract through 2045 and to co-operate on the development of uranium conversion capacity. November • We issue $400 million of 3.75% unsecured debentures due in 2022. • We issue $100 million of 5.09% unsecured debentures due in 2042. December • We complete the acquisition of the Yeelirrie uranium project. |  | January • We complete the acquisition of NUKEM. May • We begin production at North Butte uranium mine in Wyoming. June • We receive an eight-year operating licence for Cigar Lake. July • We enter into a three-year collective agreement with approximately 250 unionized employees at our conversion facility in Port Hope, Ontario. October • We receive 10-year operating licences for McArthur River, Key Lake and Rabbit Lake. December • Inkai receives approval to increase annual production from blocks 1 and 2 to 5.2 million pounds (100% basis). |  | January • We enter into an agreement to sell our interest in BPLP which is described in greater detail on page 71.

2013 ANNUAL INFORMATION FORM Page 8

How Cameco was formed

Cameco Corporation was incorporated under the Canada Business Corporations Act on June 19, 1987.

We were formed when two crown corporations were privatized and their assets merged:

• |  | Saskatchewan Mining Development Corporation (uranium mining and milling operations)

• |  | Eldorado Nuclear Limited (uranium mining, refining and conversion operations) (now Canada Eldor Inc.).

There are constraints and restrictions on ownership of Cameco shares set out in our company articles, and a related requirement to maintain offices in Saskatchewan. These are requirements of the Eldorado Nuclear Limited Reorganization and Divestiture Act (Canada), as amended, and The Saskatchewan Mining Development Corporation Reorganization Act, and are described on pages 124 and 125.

We have made the following amendments to our articles:

2002 |  | • |  | increased the maximum share ownership for individual non-residents to 15% from 5%
|  | • |  | increased the limit on voting rights of non-residents to 25% from 20%
2003 |  | • |  | allowed the board to appoint new directors between shareholder meetings as permitted by the Canada Business Corporations Act, subject to certain limitations
|  | • |  | eliminated the requirement for the chairman of the board to be ordinarily resident in the province of Saskatchewan

We have five main subsidiaries:

• |  | Cameco Europe Ltd. (Cameco Europe), a Swiss company we have 100% ownership of through subsidiaries

• |  | Our wholly owned subsidiaries Cameco Bruce Holdings Inc., a Canadian company, and Cameco Bruce Holdings II Inc., an Ontario company, which collectively own a 31.6% limited partnership interest in BPLP, an Ontario limited partnership

• |  | NUKEM Investments GmbH, a German company we have 100% ownership of through subsidiaries

• |  | Joint Venture Inkai Limited Liability Partnership (Inkai), a limited liability partnership in Kazakhstan, which we own a 60% interest in.

At December 31, 2013, we do not have any other subsidiaries that are material, either individually or collectively.

For more information

You can find more information about Cameco on SEDAR (sedar.com), EDGAR (sec.gov) and on our website (cameco.com/investors).

See our most recent management proxy circular for additional information, including how our directors and officers are compensated and any loans to them, principal holders of our securities, and securities authorized for issue under our equity compensation plans. We expect the circular for our May 2014 annual meeting of shareholders to be available in April 2014.

See our 2013 financial statements and 2013 MD&A for additional financial information.

2013 ANNUAL INFORMATION FORM Page 9

Our markets

Demand

The long-term outlook for the uranium industry continues to be very positive, despite the uncertainty that exists today. The challenge for the industry is the pathway and timing of the transition from today’s stagnant, over-supplied short-term market to the promise of nuclear growth and positive uranium market conditions in the long-term.

Market conditions deteriorated in 2013 and we believe the uncertainty could continue, depending on how events unfold. In particular, the slower than expected pace of Japanese reactor restarts, unexpected reactor shutdowns in the United States and temporary shutdowns in South Korea led to demand erosion. Compounding the issue, the supply side performed well: primary supply remained stable while secondary supply increased modestly, primarily due to enricher underfeeding. The impact of these conditions was the extension of the post-Fukushima inventory overhang and further downward price pressure.

This market dynamic also led to a reduction in market contracting activity. Utilities are well covered under long-term contracts for the time being and are not under pressure to buy. Similarly, existing suppliers appear reluctant to enter into meaningful contract volumes at current prices. The result was very low levels of long-term contracting in 2013 - around 10% of current annual reactor consumption estimates, highlighting a cordial stalemate between buyers and sellers. How this stalemate is resolved between buyers and sellers will be a key factor influencing the pace of market recovery.

Looking beyond the current market challenges, there were several positive indications for the long term in 2013. In Japan, more clarity was gained around the process for reactor restarts: the Nuclear Regulatory Authority (NRA) implemented measures that improved regulatory stability; restart applications were submitted by seven utilities covering 16 reactors; and, there was observable confidence from Japanese utilities who are spending billions of dollars on plant upgrades in anticipation of a positive restart environment.

In other regions, China’s remarkable nuclear growth program remains on track. Three more reactors were brought online, and construction began on four more in 2013. The United Kingdom (UK) also garnered positive attention as a result of a government-backed revenue arrangement with Électricité de France, designed to support new build there. Overall, the anticipated increase in nuclear plants from 433 (representing 394 gigawatts) today to 526 (representing 514 gigawatts) by 2023 illustrates a promising growth picture.

The demand for U3O8 is directly linked to the level of electricity generated by nuclear power plants. As the number of reactors grows, so too does the demand for uranium.

2013 ANNUAL INFORMATION FORM Page 10

World annual uranium fuel consumption has increased from 75 million pounds U3O8 in 1980 to an estimated 167 million pounds in 2013. We expect global uranium consumption to increase to about 170 million pounds in 2014 and global production to be approximately 160 million pounds. Secondary supplies should continue to bridge the gap.

Over the next decade, we expect world demand to grow at an average annual growth rate of about 4%, totaling approximately 2.2 billion pounds from 2014-2023. As a result of that growth, by 2023, we expect annual world consumption to be approximately 240 million pounds, plus about 20 million pounds per year for strategic inventory building, totaling 260 million pounds of world demand.

The demand for UF6 conversion services is directly linked to the level of electricity generated by light water moderated nuclear power plants.

The demand for UO2 conversion services is linked to the level of electricity generated by heavy water moderated nuclear power plants such as CANDU reactors.

We expect world consumption for conversion services to increase similar to uranium.

Supply

Uranium supply sources include primary production (production from mines that are currently in commercial operation) and secondary supply sources (excess inventories, uranium made available from defence stockpiles and the decommissioning of nuclear weapons, re-enriched depleted uranium tails, and used reactor fuel that has been reprocessed).

To meet global demand over the next 10 years, we estimate:

• |  | roughly two-thirds of global uranium supply to come from existing primary production

• |  | approximately 15% will come from existing secondary supply sources

• |  | approximately 20% will come from new sources of supply.

Primary production

While the uranium production industry is international in scope, there are only a small number of companies operating in relatively few countries. In addition, there are barriers to entry and the lead time for new uranium production can be as long as 10 years or more, depending on the deposit type and location. Many producers have announced delays and cancellations to their projects, which could have an effect on the longer term outlook for the uranium industry. Complicating the supply outlook further is the possibility of some projects, primarily driven by sovereign interests, moving forward in the near term despite market conditions.

We expect existing primary production to decrease over the next decade, falling to 120 million pounds by 2023 and highlighting the need for new primary supply.

We estimate world mine production in 2013 was about 156 million pounds U3O8, up 3% from 152 million pounds in 2012:

• |  | 94% of the estimated world production came from eight countries: Kazakhstan (38%), Canada (16%), Australia (11%), Niger (8%), Namibia (8%), Russia (5%), Uzbekistan (4%), and the US (4%)

• |  | 67% of the estimated world production was marketed by five producers. We accounted for about 15% of that production (23.6 million pounds).

Secondary sources

Uranium consumption has outstripped uranium production every year since 1985.

A number of secondary sources have covered the shortfall, but most of these sources are finite and will not meet long-term needs:

• |  | Uranium from dismantled Russian nuclear weapons was the largest source of secondary supply. Deliveries from this source ended in 2013, when the Russian HEU commercial agreement expired.

• |  | The US government makes some of its inventories available to the market, although in smaller quantities.

• |  | Utilities, mostly in Europe and some in Japan and Russia, use reprocessed uranium and plutonium from used reactor fuel.

• |  | Re-enriched depleted uranium tails and uranium from underfeeding are also generated using excess enrichment capacity.

2013 ANNUAL INFORMATION FORM Page 11

Uranium from nuclear disarmament

In February 1993, the United States and Russia signed an agreement to manage the sale of highly enriched uranium (HEU) derived from dismantling Russian nuclear weapons (Russian HEU agreement). The agreement allowed Russia to dilute 500 tonnes of HEU derived from dismantled weapons, and deliver it to the US as low enriched uranium suitable for use in nuclear power plants (disarmament LEU). Russia has implemented its plans to dilute the 500 tonnes.

This is equivalent to a total of about 400 million pounds of natural uranium as U3O8 (disarmament uranium), all of which has now been delivered to the western companies.

Russian HEU commercial agreement

In March 1999, we and other members of a consortium of western companies (AREVA and NUKEM) signed the Russian HEU commercial agreement with JSC Techsnabexport (Tenex), the commercial arm of the Russian Ministry for Atomic Energy. Under the agreement, the western companies were granted options to purchase a majority of the disarmament uranium. We exercised our options and have been receiving deliveries of disarmament uranium. We received approximately 10 million pounds of disarmament uranium in 2013. This was the final amount delivered to us under the agreement. Our subsidiary NUKEM also received its final deliveries of approximately 2 million pounds in 2013.

Trade restraints and policies

The sale of disarmament uranium into the US market is regulated by the USEC Privatization Act, which currently imposes an annual quota of 20 million pounds U3O8 equivalent on the sale of disarmament uranium. This quota, administered by the US Department of Commerce, is scheduled to expire at the end of 2014.

The US entered into a suspension agreement with Russia as part of uranium anti-dumping proceedings in the early 1990s. In February 2008, the US and Russia amended the agreement, allowing Russia to directly supply additional uranium to US utilities in very low annual amounts from 2011 to 2013. Russia can also supply uranium for initial cores in new US reactors. With the end of the Russian HEU commercial agreement in 2013, the annual amount increases to 13 million pounds U3O8 equivalent from 2014 to 2020.

The US restrictions do not affect the sale of Russian uranium to other countries. About 75% of world uranium demand is from utilities in countries that are not affected by the US restrictions. Utilities in some countries, however, adopt policies that limit the amount of Russian uranium they will buy. The Euratom Supply Agency in Europe must approve all uranium related contracts for members of the EU, and limits the use of certain nuclear fuel supplies from any one source to maintain security of supply, although these limits do not apply to uranium sold separately from enriched uranium product.

Uranium from US inventories

We estimate that the US Department of Energy (DOE) has an excess uranium inventory of roughly 125 million pounds U3O8 equivalent. We expect a sizeable portion of this uranium will be available to the market over the next two decades, although a significant portion of the inventory requires either further processing or the development of commercial arrangements before it can be brought to market.

In March 2008, the DOE issued a policy statement and a general framework for managing this inventory, including the need to dispose of it without disrupting the commercial markets. In December of that year, it released the Excess Uranium Inventory Management Plan, which stated that it will dispose of the surplus annually, in amounts of 10% or less of annual US nuclear fuel requirements. It can exceed this limit in certain situations, however (during initial core loads for new reactors, for example).

The DOE updated its Excess Uranium Inventory Management Plan in 2012. In July 2013, the DOE again updated its Excess Uranium Inventory Management Plan. Overall, total UF6 volumes and future sales referenced in the plan are generally in line with industry expectations. However, the revised plan removes the well-known guideline which had limited DOE uranium excess inventory sales to 10% of US reactor fuel requirements. There is potential for this to impact the uranium market; however, DOE sales will continue to be governed by Secretarial Determinations, which require that any such sales not have a material adverse impact on the US uranium, conversion and enrichment industries.

Conversion services

We control about 25% of world UF6 conversion capacity and are a supplier of UO2 for Canadian-made CANDU reactors.

2013 ANNUAL INFORMATION FORM Page 12

Marketing

We sell uranium and fuel services (as uranium concentrates, UO2, UF6, conversion services or fuel fabrication) to nuclear utilities in Belgium, Canada, China, Finland, France, Germany, Japan, South Korea, Spain, Sweden, Taiwan, United Kingdom and the US. We are a supplier of UO2 to CANDU reactors operated in Canada.

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.

In June 2010, the government of Canada signed a civil nuclear co-operation agreement with India to export nuclear technology, equipment and uranium to support India’s growing nuclear energy industry. Licensing arrangements for these exports were ratified by the two governments in 2013.

We are in contact with India to explore opportunities to supply uranium to their growing reactor program.

In 2010, we signed two long-term agreements with Chinese utilities to supply more than 50 million pounds of uranium. In February 2012, the governments of Canada and China announced an agreement on the terms of a protocol that would facilitate the export of Canadian uranium to China. These arrangements were subsequently ratified by the two governments in 2012 and Canadian uranium can be exported to China.

In November 2013, the government of Canada signed a nuclear co-operation agreement with Kazakhstan. The nuclear co-operation agreement and related administration agreements are complete and next steps will include tabling the agreement in both parliaments and exchange of diplomatic notes before the agreement is in force. For us, the nuclear co-operation agreement opens opportunities to advance our partnership with Kazakhstan which will strengthen our business and support continued growth.

Our sales commitments

In 2013, 45% of our U3O8 sales were to five customers.

We currently have commitments to supply about 230 million pounds of U3O8 under long-term contracts with 45 customers worldwide. Our five largest customers account for 50% of these commitments, and 36% of our committed sales volume is attributed to purchasers in the Americas (US, Canada and Latin America), 41% in Asia and 23% in Europe. We are heavily committed under long-term uranium contracts through 2017, so we are being selective when considering new commitments.

Our subsidiary NUKEM also signs long-term contracts and has uranium and uranium-related products under contract until 2022.

Our purchase commitments

In addition, we are active in the spot market buying and selling uranium where it is beneficial for us. With our purchase of NUKEM, we have enhanced our ability to participate in this regard 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. This activity gives us insight into the underlying market fundamentals and is a source of profit. We have also bought uranium under long-term contracts, and may do so again in the future. At December 31, 2013, we had firm commitments to buy about 21 million pounds of uranium equivalent from 2014 to 2022.

Our marketing strategy

The purpose of our marketing strategy is to deliver value and secure a solid base of earnings and cash flow, by maintaining a balanced contract portfolio that optimizes our realized price.

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.

2013 ANNUAL INFORMATION FORM Page 13

We target a ratio of 40% fixed-price contracts and 60% market-related contracts. This is a balanced and flexible approach that allows us to adapt to market conditions, reduce the volatility of our future earnings and cash flow, and that we believe delivers the best value to shareholders over the long term. It is also consistent with the contracting strategy of our customers.

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

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

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

Our extensive portfolio of long-term sales contracts – and the long-term, trusting relationships we have with our customers – are core strengths for us.

Volumes and pricing

The Ux Consulting estimate for global spot market sales in 2013 was about 50 million pounds, similar to previous years. The Ux Consulting estimate for global long-term contracting in 2013 was about 20 million pounds of U3O8, compared to 194 million pounds of U3O8 in 2012. Neither buyers nor suppliers are under significant pressure to contract, and suppliers are likely hesitant to lock in meaningful volumes at current price levels.

The industry average spot price (TradeTech and Ux Consulting) on December 31, 2013 was $34.50 (US) per pound U3O8, or 20% lower than the December 31, 2012 average of $43.38 (US).

The industry average long-term price (TradeTech and Ux Consulting) was $50.00 (US) per pound U3O8 on December 31, 2013, or 12% lower than the December 31, 2012 average of $56.50 (US).

Since the Fukushima nuclear incident in Japan, spot and term prices have experienced downward pressure. Reductions in industry demand projections and concerns about excess inventory coming to the market are the major contributing factors, prompted by immediate and expected plant closures in countries such as Germany and Japan in 2011 and by prolonged reactor restarts in Japan and a temporary pause in China new build approvals.

Fuel services

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.

For conversion services, we compete with three other primary commercial suppliers, in addition to the secondary supplies described above, to meet global demand.

We have a similar marketing strategy for UF6 conversion services. We sell our conversion services to utilities in the Americas, Europe and Asia and primarily through long-term contracts. We currently have UF6 conversion services commitments of approximately 80 million kilograms of UF6 conversion services under long-term contracts with 41 customers worldwide. Our five largest customers account for 54% of these commitments, and of our committed UF6 conversion services volume, 40% is attributed to purchasers in the Americas, 25% in Asia and 35% in Europe.

In 2014, we plan to produce 13 million to 14 million kgU.

NUKEM

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

2013 ANNUAL INFORMATION FORM Page 14

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

Electricity business

BPLP operates four CANDU nuclear reactors that have the capacity to provide about 15% of Ontario’s electricity.

It receives a reliable stream of revenue from the sale of electricity to the Ontario electricity market. BPLP has an agreement with the Ontario Power Authority (OPA) that supports output from the B reactors with a floor price (currently $52.34/MWh) adjusted annually for inflation. During 2013, BPLP recognized revenue of $698 million under the agreement with the OPA, compared to $773 million in 2012.

The floor price mechanism and any associated payments to BPLP for the output from each Bruce B reactor will expire on a date specified in the agreement. The expiry dates are June 30, 2019 for unit B5, April 30, 2020 for unit B6, August 31, 2020 for unit B7 and December 31, 2020 for unit B8. Revenue is recognized monthly, based on the positive difference between the floor price and the spot price. BPLP does not have to repay the revenue from the agreement with the OPA, if the floor price for the particular year exceeds the average spot price for that year.

The agreement also provides for payment if the Independent Electricity System Operator reduces BPLP’s generation because Ontario baseload generation is higher than required. The amount of the reduction is considered “deemed generation”, and BPLP is paid either the spot price or the floor price, whichever is higher. The compensation for “deemed generation” is a reflection of the unique flexibility of output in the market that the Bruce B units provide and the relatively high fixed cost nature of the business.

Spot market prices in Ontario are determined by bids from suppliers and buyers that reflect changes in supply and demand by the hour. BPLP also trades electricity as part of its risk management activities. In 2013, 5% of its output was sold under financial contracts on a net basis.

Demand for electricity in Ontario has changed considerably due to economic changes in the province following the 2008 recession and the introduction of embedded generation through the Green Energy Act. Ontario demand in 2013 was down by 0.7% or 1.0 TWh compared to 2012 (demand in 2012 is after adjusting for the impact of the leap year) mainly due to a relatively mild summer and fall in 2013 and the growth in embedded generation which led to a reduction in demand. While wholesale consumption continued to exhibit some strength, gaining 3% or 0.4 TWh from 2012 (demand in 2012 is after adjusting for the impact of the leap year), we believe it will take some time for demand to return to prior levels consistent with the demand assumptions recently made in Ontario’s Long Term Energy Plan.

Sales to BPLP and Bruce Power A Limited Partnership (BALP) are a substantial portion of our fuel manufacturing business and an important part of our UO2 business.

Nuclear power stations have higher operational, maintenance, waste and decommissioning costs than other methods of generating electricity. They also require more initial capital for development because of the complexity of the technical processes that underlie nuclear power generation, and the additional design, security and safety precautions to protect the public from potential risks associated with nuclear operations.

The relatively low cost of nuclear fuel compared to fossil fuel offsets these costs. In general, BPLP’s nuclear stations have a lower overall operating cost per megawatt-hour of electricity produced than facilities that use fossil fuels.

2013 ANNUAL INFORMATION FORM Page 15

Operations and development projects

Uranium

Operating properties |  |  |  |
McArthur River/Key Lake |  |  | 17 |
Rabbit Lake |  |  | 31 |
Smith Ranch-Highland |  |  | 33 |
Crow Butte |  |  | 33 |
Inkai |  |  | 35 |
Development project |  |  |  |
Cigar Lake |  |  | 47 |
Projects under evaluation |  |  |  |
Inkai blocks 1 and 2 production increase (see Inkai, above) |  |  | 35 |
Inkai block 3 (see Inkai, above) |  |  | 35 |
Millennium |  |  | 61 |
Yeelirrie |  |  | 62 |
Kintyre |  |  | 63 |
Exploration |  |  | 64 |

Fuel services

Refining |  |  |  |
Blind River refinery |  |  | 65 |
Conversion and fuel manufacturing |  |  |  |
Port Hope conversion services |  |  | 66 |
Cameco Fuel Manufacturing Inc. |  |  | 66 |
Springfields Fuels Ltd. |  |  | 66 |

NUKEM

NUKEM GmbH |  | 69

Electricity

Bruce Power Limited Partnership |  |  | 70 |

Uranium production

Cameco’s share (million lbs U3O8) |  | 2011 |  |  | 2012 |  |  | 2013 |
McArthur River/Key Lake |  |  | 13.9 |  |  |  | 13.6 |  |  |  | 14.1 |
Rabbit Lake |  |  | 3.8 |  |  |  | 3.8 |  |  |  | 4.1 |
Smith Ranch-Highland |  |  | 1.4 |  |  |  | 1.1 |  |  |  | 1.7 |
Crow Butte |  |  | 0.8 |  |  |  | 0.8 |  |  |  | 0.7 |
Inkai |  |  | 2.5 |  |  |  | 2.6 |  |  |  | 3.0 |
Total |  |  | 22.4 |  |  |  | 21.9 |  |  |  | 23.6 |

2013 ANNUAL INFORMATION FORM Page 16

Uranium – operating properties

|  | McArthur River/Key Lake McArthur River is the world’s largest high-grade uranium mine, and Key Lake is the largest uranium mill in the world. Ore grades at the McArthur River mine are 100 times the world average, which means it can produce more than 18 million pounds per year by mining only 150 to 200 tonnes of ore per day. We are the operator. McArthur River is one of our three material uranium properties.
Location |  | Saskatchewan, Canada
Ownership |  | 69.805% - McArthur River
|  | 83.33% - Key Lake
End product |  | uranium concentrates
ISO certification |  | ISO 14001 certified
Mine type |  | underground
Estimated mineral reserves |  | 251.6 million pounds (proven and probable)
(our share) |  | average grade U3O8 – 15.76%
Estimated mineral resources |  | 9.5 million pounds (measured and indicated)
(our share) |  | average grade U3O8 – 4.81%
|  | 39.9 million pounds (inferred)
|  | average grade U3O8 – 7.38%
Mining methods |  | primary: raiseboring
|  | secondary: blasthole stoping and boxhole boring
Licensed capacity |  | mine and mill: 18.7 million pounds per year
|  | (can be exceeded – see Production below)
Total production 2000 to 2013 |  | 250.6 million pounds (McArthur River/Key Lake)
(100% basis) 1983 to 2002 |  | 209.8 million pounds (Key Lake)
2013 production (our share) |  | 14.1 million pounds
2014 forecast production (our share) |  | 13.1 million pounds
Estimated mine life |  | 2034 (based on current mineral reserves)
Estimated decommissioning cost |  | $48 million - McArthur River
(100% basis) |  | $218 million - Key Lake (estimate currently under review)

2013 ANNUAL INFORMATION FORM Page 17

Business structure

McArthur River is owned by a joint venture between two companies: |  | Key Lake is owned by a joint venture between the same two companies:
• Cameco – 69.805% |  | • Cameco –83 1⁄3%
• AREVA – 30.195% |  | • AREVA – 16 2⁄3%

History

1976 |  | • |  | Canadian Kelvin Resources Ltd. and Asamera Oil Corporation Ltd. form an exploration joint venture, which
|  |  |  | includes the lands that the McArthur River mine is situated on
1977 |  | • |  | Saskatchewan Mining Development Corporation (SMDC), one of our predecessor companies, acquires a 50%
|  |  |  | interest
1980 |  | • |  | McArthur River joint venture is formed
|  | • |  | SMDC becomes the operator
|  | • |  | Active surface exploration begins
|  | • |  | Between 1980 and 1988 SMDC reduces its interest to 43.991%
1988 |  | • |  | Eldorado Resources Limited merges with SMDC to form Cameco
|  | • |  | We become the operator
|  | • |  | Deposit discovered by surface drilling
1988-1992 |  | • |  | Surface drilling reveals significant mineralization of potentially economic uranium grades, in a 1,700 metre zone at between 500 to 640 metres
1992 |  | • |  | We increase our interest to 53.991%
1993 |  | • |  | Underground exploration program receives government approval – program consists of shaft sinking (completed
|  |  |  | in 1994) and underground development and drilling
1995 |  | • |  | We increase our interest to 55.844%
1997-1998 |  | • |  | Federal authorities issue construction licences for McArthur River after reviewing the environmental impact statement, holding public hearings, and receiving approvals from the governments of Canada and
|  |  |  | Saskatchewan
1998 |  | • |  | We acquire all of the shares of Uranerz Exploration and Mining Ltd. (UEM), increasing our interest to 83.766%
|  | • |  | We sell half of the shares of UEM to AREVA, reducing our interest to 69.805%, and increasing AREVA’s to 30.195%
1999 |  | • |  | Federal authorities issue the operating licence and provincial authorities give operating approval, and mining begins in December
2003 |  | • |  | Production is temporarily suspended in April because of a water inflow
|  | • |  | Mining resumes in July
2009 |  | • |  | UEM distributes equally to its shareholders:
|  |  |  | • |  | its 27.922% interest in the McArthur River joint venture, giving us a 69.805% direct interest, and AREVA a
|  |  |  |  |  | 30.195% direct interest
|  |  |  | • |  | its 33 1⁄3% interest in the Key Lake joint venture, giving us an 83 1⁄3% direct interest, and AREVA a 16 2⁄3% direct
|  |  |  |  |  | interest.
2013 |  | • |  | Federal authorities granted a 10-year renewal of the McArthur River and Key Lake operating licences

2013 ANNUAL INFORMATION FORM Page 18

Technical report

This project description is based on the project’s technical report: McArthur River Operation, Northern Saskatchewan, Canada, dated November 2, 2012 (effective August 31, 2012) except for some updates that reflect developments since the technical report was published. The report was prepared for us in accordance with Canadian National Instrument 43-101 – Standards of Disclosure for Mineral Projects (NI 43-101), by or under the supervision of four Cameco qualified persons within the meaning of NI 43-101. The following description has been prepared under the supervision of David Bronkhorst, P. Eng., Alain G. Mainville, P. Geo., Gregory M. Murdock, P. Eng., and Leslie D. Yesnik, P. Eng. These people are all qualified persons within the meaning of NI 43-101, but are not independent of us.

For information about uranium sales see pages 13 to 14, environmental matters see Safety, Health and Environment starting on page 84, and taxes see pages 97 to 99.

For a description of royalties payable to the province of Saskatchewan on the sale of uranium extracted from orebodies within the province, see page 97.

The conclusions, projections and estimates included in this description are subject to the qualifications, assumptions and exclusions set out in the technical report, except as such qualifications, assumptions and exclusions may be modified in this AIF. We recommend you read the technical report in its entirety to fully understand the project. You can download a copy from SEDAR (sedar.com) or from EDGAR (sec.gov).

About the McArthur River property

Location

Near Toby Lake in northern Saskatchewan, 620 kilometres north of Saskatoon. The mine site is approximately one square kilometre, not including the nearby airstrip and camp facilities.

Accessibility

Access to the property is by an all-weather gravel road and by air. Supplies are transported by truck from Saskatoon and elsewhere. There is a 1.6 kilometre unpaved air strip and an air terminal one kilometre east of the mine site, on the surface lease.

Saskatoon, a major population centre south of the McArthur River property, has highway and air links to the rest of North America.

Leases

Surface lease

We acquired the right to use and occupy the lands necessary to mine the deposit under a surface lease agreement with the province of Saskatchewan. The most recent agreement was signed in November 2010. It covers 1,425 hectares and has a term of 33 years.

We are required to report annually on the status of the environment, land development and progress on northern employment and business development.

Mineral lease

We have the right to mine the deposit under ML-5516, granted to us by the province of Saskatchewan. The lease covers 1,380 hectares and expires in March 2024. We have the right to renew the lease for further 10-year terms.

Mineral claims

A mineral claim gives us the right to explore for minerals and to apply for a mineral lease. There are 21 mineral claims, totaling 83,438 hectares, surrounding the deposit. The mineral claims are in good standing until 2018, or later.

Climate

The climate is typical of the continental sub-arctic region of northern Saskatchewan. Summers are short and cool even though daily temperatures can sometimes reach above 30°C. The mean daily temperature for the coldest month is below -20°C, and winter daily temperatures can reach below -40°C.

2013 ANNUAL INFORMATION FORM Page 19

Setting

The deposit is in the southeastern portion of the Athabasca basin in northern Saskatchewan, within the southwest part of the Churchill structural province of the Canadian Shield. The topography and environment are typical of the taiga forested lands in the Athabasca basin.

Geology

The crystalline basement rocks underlying the deposit are members of the Aphebian-age Wollaston Domain, metasedimentary sequence. These rocks are overlain by flat lying sandstones and conglomerates of the Helikian Athabasca Group. These sediments consist of the A, B, C and D units of the Manitou Falls Formation, and a basal conglomerate containing pebbles and cobbles of quartzite. These sediments are over 500 metres thick in the deposit area.

Mineralization

McArthur River’s mineralization is structurally controlled by a northeast-southwest trending reverse fault (the P2 fault), which dips 40-65 degrees to the southeast. The fault has thrust a wedge of basement rock into the overlying sandstone. There is a vertical displacement of more than 80 metres at the northeast end of the fault, which decreases to 60 metres at the southwest end.

The deposit consists of nine distinct mineralized areas and two under-explored surface defined mineralized showings over a strike length of 2,700 metres. Five of these have been well defined with underground drilling, namely Zones 1 to 4 and 4 South. The remaining four, McA North (1), McA North (2), Zone A and Zone B are based entirely on surface drilling.

The width of the mineralization varies. The main part of the mineralization, generally at the upper part of the wedge, averages 12.7 metres in width and attains a maximum width of 28 metres (Zone 2). The height of the mineralization ranges from 50 metres to 120 metres.

With the exception of Zone 2, the mineralization occurs in both the sandstone and basement rock along the faulted edge of the basement wedge. Zone 2 occurs deeper in the basement rock in a unique area of the deposit, where a massive footwall quartzite unit lies close to the main fault zone.

Although all of the rocks at McArthur River are altered to some degree, the alteration is greatest in or near faults that are often associated with mineralization. Chloritization is common and most intense within a metre of mineralization in the pelitic hanging wall basement rocks above the P2 fault. The predominant alteration characteristic of the sandstone is pervasive silicification, which increases in intensity 375 metres below the surface, and continues to the unconformity. This brittle sandstone is strongly fractured along the path of the main fault zone, resulting in poor ground conditions and high permeability to water.

In general, the high-grade mineralization, characterized by botryoidal uraninite masses and subhedral uraninite aggregates, constitutes the earliest phase of mineralization in the deposit. Pyrite, chalcopyrite, and galena were also deposited during the initial mineralizing event. Later stage, remobilized uraninite occurs as disseminations, veinlets, and fracture coatings within chlorite breccia zones, and along the margins of silt beds in the Athabasca sandstone.

2013 ANNUAL INFORMATION FORM Page 20

Orthogonal View of Underground Development and Mineralized Zones Looking Northwest

About the McArthur River mine

McArthur River is a producing property with sufficient surface rights to meet current mining operation needs.

We began construction and development of the McArthur River mine in 1997 and completed it on schedule. Mining began in December 1999 and commercial production on November 1, 2000.

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

We started mining Zone 2 in 1999. It is divided into four panels (panels 1, 2, 3 and 5) based on the configuration of the freeze wall around the ore. Panel 5 represents the upper portion of Zone 2, overlying part of the other panels. Mining is near completion in panels 1, 2 and 3 and the majority of the remaining Zone 2 proven mineral reserves are in panel 5.

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

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

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

2013 ANNUAL INFORMATION FORM Page 21

Permits

We need three key permits to operate the McArthur River mine:

• |  | Uranium Mine Facility Operating Licence – renewed in 2013 and expires on October 31, 2023 (from the Canadian Nuclear Safety Commission (CNSC))

• |  | Approval to Operate Pollutant Control Facilities – renewed in 2009 and expires on October 31, 2014 (from the Saskatchewan Ministry of Environment)

• |  | Water Rights Licence and Approval to Operate Works – amended in 2011 and valid for an undefined term (from the Saskatchewan Watershed Authority).

Infrastructure

Surface facilities are 550 metres above sea level. The site includes:

• |  | an underground mine with three shafts:

one full surface shaft and two ventilation shafts

• |  | 1.6 kilometre airstrip and air terminal

• |  | waste rock stockpiles

• |  | water containment ponds and treatment plant

• |  | a freshwater pump house

• |  | a powerhouse

• |  | electrical substations

• |  | standby electrical generators

• |  | a warehouse

• |  | a freeze plant

• |  | a concrete batch plant

• |  | an administration and maintenance shop building

• |  | a permanent residence and recreation complex

• |  | an ore slurry load out facility.

To support changes to the production schedule, we plan to expand mine infrastructure (see McArthur River production expansion on pages 24 and 25 for more information).

Water, power and heat

Toby Lake, which is nearby and easy to access, has enough water to satisfy all surface water requirements. Water leaking into the shafts is sufficient to meet all underground process water requirements. The site is connected to the provincial power grid, and it has standby generators in case there is an interruption in grid power.

McArthur River operates throughout the year despite cold winter conditions. During the winter, we heat the fresh air necessary to ventilate the underground workings using propane-fired burners.

Employees

Employees are recruited first from communities in the area and then from major Saskatchewan population centres, like Saskatoon.

Mining method

We use a number of innovative methods and techniques 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 the water in the sandstone from entering the mine, and helps stabilize weak rock formations. Ground freezing reduces, but does not eliminate, the risk of water inflows. To date, we have installed five freeze walls and are currently preparing a sixth.

Raisebore mining

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

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

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

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

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

• |  | starting the process again with the next raisebore chamber.

2013 ANNUAL INFORMATION FORM Page 22

We have successfully used the raisebore mining method to extract about 250 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.

In 2013, the CNSC granted approval for the use of two secondary extraction methods: blasthole stoping and boxhole boring. Test programs for each method were completed in the first half of the year. We expect that these extraction methods will only be used in limited situations to complement our primary extraction method of raiseboring.

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 only a few mines around the world, but had not been used for uranium mining prior to testing at McArthur River.

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

Blasthole stoping

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

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

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.

Tailings

McArthur River does not have a tailings management facility because it ships the ore slurry to Key Lake for milling.

Waste

The waste rock piles are confined to a small footprint on the surface lease. These are separated into three categories:

• |  | clean rock (includes mine development waste, crushed waste, and various piles for concrete aggregate and backfill)

• |  | mineralized waste (>0.03% U3O8) – stored on engineered lined pads

• |  | waste with acid-generating potential – stored on engineered lined pads – for concrete aggregate.

Water inflows

Production was temporarily suspended on April 6, 2003, as increased water inflow due to a rock fall in a new development area (located just above the 530 metre level) began to flood portions of the mine. We resumed mining in July 2003 and sealed off the excess water inflow in July 2004.

In November 2008, there was a small water inflow in the lower Zone 4 development area on the 590 metre level. We captured and controlled the inflow, and did not have to alter our mining plan. We completed a freezewall in this area in 2010, and are now mining in the area.

These two inflows have strongly influenced mine design, inflow risk mitigation and inflow preparedness.

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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 we begin work on any new zone. We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum sustained inflow. As our mine plan is advanced, we plan to make improvements in our dewatering system and to expand our water treatment capacity.

Production

• |  | 2013: 20.1 million pounds of U3O8 was produced by milling McArthur River ore at Key Lake (our share was 14.1 million pounds). Average mill metallurgical recovery was 99.27%.

• |  | Forecast: 18.7 million pounds of U3O8 (our share 13.1 million pounds) until we receive the required regulatory approvals and complete the work necessary to increase production at both McArthur River and Key Lake (see McArthur River production expansion below). The total life-of-mine mill production forecast as of December 31, 2013 is estimated to be 355.8 million pounds of U3O8 (our share 248.4 million pounds), based on an overall milling recovery of 98.7%.

In 2013, the operating licences for McArthur River and Key Lake were renewed. As part of the renewal process, the production limits for McArthur River and Key Lake are now set by the licence conditions handbooks.

As long as average annual production does not exceed 18.7 million pounds per year, production flexibility provisions in the licence conditions handbooks allow:

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

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

Our average annual production at McArthur River/Key Lake over the past five years is 19.7 million pounds. Consequently, we have limited flex capacity remaining under our licence provisions.

Payback

Payback for us, including all actual costs was achieved in 2010, on an undiscounted pre-tax basis. Operating cash flow is forecast to be sufficient to cover all planned capital expenditures.

Recent activity

Zone 4 North is the next area we expect to mine. We began freezing the ground in the third quarter of 2013, with plans to start mining the zone in 2014. We expect to use raisebore mining in this area, applying the ground freezing experience we gained in Zone 2, panel 5. This should significantly improve production efficiencies compared to boxhole boring.

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

McArthur River production expansion

A limiting factor for production at the McArthur River mine is the licence limit of 18.7 million pounds (100% basis) per year, and in order to maintain the flexibility to produce more, we plan to request a production limit increase to 21 million pounds (100% basis) in 2014. This would match the currently approved maximum production level. We expect a decision on this increase in 2014.

In addition, we will continue the work to further increase our annual production rate to 22 million pounds (100% basis) by 2018, subject to regulatory approval, as contemplated in the revision to our mine plan in 2012.

We were notified by the CNSC that the environmental assessment for the planned increase in production to 22 million pounds would be transitioned to the CNSC licensing and compliance processes, rather than the federal environmental assessment process.

In order to implement the planned production increase, we must continue to successfully transition into new mine areas through mine development and investment in support infrastructure. In addition, we plan to:

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• |  | obtain all the necessary regulatory approvals, including at Key Lake, to ensure the mill can process all of the ore mined annually at McArthur River

• |  | expand the freeze plant and electrical distribution systems

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

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

We have started to upgrade our electrical infrastructure to address the future need for increased ventilation and freeze capacity associated with mining new zones and increasing mine production. Our electrical expansion plans include a new 138 kilovolt substation and expansion of our back-up power, site electrical distribution and power supply.

As we advance our production plan, our ventilation demands will also increase. We plan to sink a fourth shaft at the northern end of the mine, which will be fully integrated with the existing ventilation system. Project completion for this shaft is scheduled for the end of 2017 and project optimization will continue as our plans are advanced.

Both freeze plant and distribution systems will have to be expanded as new mining areas are developed and brought into production. Freeze plant capacity is expected to be expanded in three stages as follows:

• |  | Expansion of the existing freeze plant: Expansion of the existing freeze plant from 800 tonnes to 1,300 tonnes is currently in progress and is expected to be completed in the first half of 2014.

• |  | South freeze plant: A 1,000 tonne freeze plant is planned for the south mining areas and is scheduled to be completed by 2017.

• |  | North freeze plant: A 1,250 tonne freeze plant is planned for the north mining areas and is scheduled to be completed by 2020. Final sizing will be determined after the completion of Zone A delineation drilling.

The underground distribution systems to the mining areas will be expanded through piping and heat exchanger additions as required.

As our mine plan is advanced, we plan to make improvements to our dewatering system and to expand our water treatment capacity. Ongoing assessment, review and optimization of mine dewatering and treatment capacity requirements are planned to continue as capital plans are advanced.

As we advance our production plan and transition into the lower grade mining areas, we also expect to expand the concrete distribution systems and batch plant capacity. Surface slick lines in both the north and south and an upgraded or new batch plant are expected to be required in approximately 2021.

Key Lake mill

Location

In northern Saskatchewan, 570 kilometres north of Saskatoon. The site is 9 kilometres long and 5 kilometres wide. It is connected to McArthur River by an 80 kilometre all-weather road. There is a 1.6 kilometre unpaved air strip and an air terminal on the east edge of the site.

Permits

We need two key permits to operate the Key Lake mill:

• |  | Uranium Mill Operating Licence – renewed in 2013 and expires on October 31, 2023 (from the CNSC)

• |  | Approval to Operate Pollutant Control Facilities – renewed in 2009 and expires on November 30, 2014 (from the Saskatchewan Ministry of Environment).

For information on the current production limits under Key Lake’s operating licence, see About the McArthur River mine – Production on page 24.

In connection with the Key Lake extension project, we have initiated an environmental assessment for the Key Lake mill to extend its operational life and establish it as a regional mill by increasing tailings capacity at the Deilmann tailings management facility and increasing the nominal annual production rate of Key Lake to 25 million pounds U3O8 (see Tailings capacity on pages 26 and 27 for more information).

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Mill production at Key Lake is expected to closely follow McArthur River mine production for the life of mine, subject to receipt of regulatory approval. There will be differences in a given production year between mine and mill production due to the addition of mineralized material stockpiled at Key Lake, year to year inventory changes and recovery rate. We are continuing to plan for average annual production of 18.7 million pounds (100% basis) for the next few years.

Supply

Our share of McArthur River ore is milled at Key Lake. We do not have a formal toll milling agreement with the Key Lake joint venture.

In June 1999, the Key Lake joint venture (us and UEM) entered into a toll milling agreement with AREVA Resources Canada Inc. (AREVA) to process their total share of McArthur River ore. The terms of the agreement (as amended in January 2001) include the following:

• |  | processing is at cost, plus a toll milling fee

• |  | the Key Lake joint venture owners are responsible for decommissioning the Key Lake mill and for certain capital costs, including the costs of any tailings management associated with milling AREVA’s share of McArthur River ore.

With the UEM distribution in 2009 (see History on page 18 for more information), we made the following changes to the agreement:

• |  | the fees and expenses related to AREVA’s pro-rata share of ore produced just before the UEM distribution (16.234% – the first ore stream) have not changed. AREVA is not responsible for any capital or decommissioning costs related to the first ore stream.

• |  | the fees and expenses related to AREVA’s pro-rata share of ore produced as a result of the UEM distribution (an additional 13.961% – the second ore stream) have not changed. AREVA’s responsibility for capital and decommissioning costs related to the second ore stream are, however, as a Key Lake joint venture owner under the original agreement.

The agreement was amended again in 2011 and now requires:

• |  | milling of the first ore stream at the Key Lake mill until May 31, 2028

• |  | milling of the second ore stream at the Key Lake mill for the entire life of the McArthur River project.

Process

The Key Lake mill uses a seven-step process:

• |  | blend McArthur River ore with low grade mineralized material to lower the grade

• |  | dissolve the uranium using a leaching circuit

• |  | clarify the uranium in solution using a counter current decantation circuit

• |  | concentrate it using a solvent extraction circuit

• |  | precipitate it with ammonia

• |  | thicken, dewater and dry it

• |  | package it as 98% U3O8 (yellowcake).

Waste rock

There are five large rock stockpiles at the Key Lake site:

• |  | three contain non-mineralized waste rock. These will be decommissioned when the site is closed.

• |  | two contain low-grade mineralized material. These are used to lower the grade of the McArthur River ore before it enters the milling circuit.

Treatment of effluent

We modified Key Lake’s effluent treatment process to reduce concentrations of molybdenum and selenium discharged into the environment, as required by our operating licence. Release of both metals to the environment is now controlled at reduced concentrations.

Tailings capacity

There are two tailings management facilities at the Key Lake site:

• |  | an above-ground impoundment facility, where tailings are stored within compacted till embankments. We have not deposited tailings here since 1996, and are looking at several options for decommissioning this facility.

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• |  | the Deilmann pit, which was mined out in the 1990s. Tailings from processing McArthur River ore are deposited in the Deilmann tailings management facility (TMF).

In 2009, regulators approved our plan for the long-term stabilization of the Deilmann TMF pitwalls. We implemented the plan, and work was completed in October 2013.

In the past, sloughing of material from the pitwalls reduced tailings capacity. We completed several studies to better understand the pitwall sloughing mechanism and completed engineering work to design and build measures to prevent sloughing. Controlling water level was an effective interim measure in managing further sloughing while work to cut back the slopes for long-term stabilization was completed. We also doubled our dewatering treatment capacity, allowing us to stabilize the water level in the pit.

In 2012, we began flattening the slope of the Deilmann TMF pitwalls, relocating about 80% of the sand. In 2013, we completed flattening of the Deilmann TMF pitwalls and constructed a toe buttress close to the current water level. The purpose of the buttress is to prevent sand sloughing when the water level is raised in the future.

At current production rates, the Deilmann TMF is forecast to be at the licensed capacity by 2018.

In connection with the Key Lake extension project, we have assessed options for long-term storage of tailings at Key Lake and are proceeding with the environmental assessment to support an application for regulatory approval to deposit tailings in the Deilmann TMF to a much higher level. This would provide enough tailings capacity to potentially 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.

In 2012, we advanced the environmental assessment for the Key Lake extension project. We submitted the draft environmental impact statement to the regulators, received their comments and provided our responses. In 2013, we submitted the final environmental impact statement for review by the regulators, and plan to pursue the required regulatory approvals in 2014.

Mill revitalization

The Key Lake mill began operating in 1983. We have a revitalization plan to maintain and increase its annual uranium production capability to up to 25 million pounds. The plan includes upgrading circuits with new technology to simplify operations and improve environmental performance. We have been refurbishing or replacing selected areas of the existing infrastructure since 2006. Our new acid, oxygen and steam plants are operational. We plan to increase tailings capacity – see Tailings capacity, above.

We also have been focusing on the product-end of the mill, including solvent extraction (SX), ammonium sulphate crystallization and calcining circuits. A project to replace the existing substation was completed in 2013. This new infrastructure has sufficient capacity to meet future electrical demands. Major components of the new calciner circuit were installed in 2013. This new equipment will also have sufficient capacity to meet long term requirements and commissioning is expected to be completed in 2014.

Decommissioning and financial assurances

In 2003, we prepared a preliminary decommissioning plan for both McArthur River and Key Lake, which were approved by the CNSC and the Saskatchewan Ministry of the Environment. In 2008, when we renewed our CNSC licence, we revised the accompanying preliminary decommissioning cost estimates. In 2013, when we again renewed our CNSC licence, we revised the accompanying preliminary decommissioning cost estimates. These documents include our estimated cost for implementing the decommissioning plan and addressing known environmental liabilities. We are discussing our Key Lake decommissioning estimate with the CNSC. Depending upon the outcome of those discussions, our estimate may increase by an immaterial amount.

We, along with our joint venture partner, are in the process of updating the letters of credit posted as financial assurances with the government of Saskatchewan to cover the amounts in the 2013 preliminary decommissioning cost estimates ($48 million for McArthur River and $218 million for Key Lake).

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Exploration, drilling and estimates

The original McArthur River resource estimates were derived from surface diamond drilling from 1980 to 1992. In 1988 and 1989, this drilling first revealed significant uranium mineralization. By 1992, we had delineated the mineralization over a strike length of 1,700 metres at depths of between 530 to 640 metres. Data included assay results from 42 drillholes. The very high grade found in the drillholes justified the development of an underground exploration project in 1993.

In total, exploration drilling of the McArthur River deposit to date consists of over 1,168 drillholes and 189,300 metres. Drilling has been carried out from both surface and underground in order to locate and delineate mineralization. Surface exploration drilling is initially used in areas where underground access is not available and is used to guide the underground exploration programs. The deposit consists of nine distinct mineralized areas and two under-explored surface defined mineralized showings over a potential strike length of 2,700 metres. Five of these have been well defined with underground drilling, namely Zones 1 to 4 and 4 South. The remaining four, McA North (1), McA North (2), Zone A and Zone B are based entirely on surface drilling. McA North (1) has recently experienced underground drilling (results pending). Underground drilling was recently started on Zone A and is ongoing. Two under-explored mineralized showings, as well as other mineralized occurrences, will be pursued if warranted.

Surface drilling

We have carried out surface drilling since 2004, to test the extension of mineralization identified from the historical surface drillholes, to new targets along the strike, and to evaluate the P2 trend northeast and southwest of the mine. Surface drilling has delineated mineralization over a strike length of 1,700 metres, generally at between 500 metres to 640 metres below the surface. Surface drilling since 2004 has extended the potential strike length to 2,700 metres.

As of December 31, 2013, we had drilled 166 surface drillholes (both conventional and directional drilling) for a total of approximately 100,000 metres along the P2 trend. This includes 13 drillholes totaling approximately 8,670 metres, completed during 2009 to confirm and further delineate the Zone B mineral resource.

We have completed preliminary drill tests of the P2 trend at 200 metre intervals over 11.5 kilometres (4.3 kilometres northeast and 6.4 kilometres southwest of the McArthur River deposit) of the total 13.75 kilometres strike length of the P2 trend. A total of $4.5 million (our share $3.14 million) has been budgeted in 2014 for surface diamond drilling to evaluate mineralization northeast of Zone B, conduct a first pass of drilling on the parallel conductor to the south, and follow up on any other anomalies. We intend to undertake drilling in 2014 to evaluate three priority areas of the P2 trend.

Underground drilling

In 1993, regulators approved an underground exploration program, consisting of shaft sinking, lateral development and drilling. We completed the shaft in 1994.

We have drilled more than 1,002 underground drillholes since 1993, over 89,300 metres, to get detailed information along 1,190 metres of the surface delineation, and used this data to estimate the mineral reserves and resources in five mineralized zones (Zones 1 to 4 and 4 South). The drilling was primarily completed from the 530 and 640 metre levels. Data from hundreds of freezeholes and raisebore pilot holes support the estimate. Where there were no underground drillholes (Zones A, B, McA North (1) and McA North (2) in the northeastern part of the deposit), we used surface exploration drillholes to estimate mineral resources.

In addition to the exploration drilling, geological data is also collected from the underground probe and grout, service, drain, freezeholes and geotechnical programs. To date, we have drilled over 2,279 holes along more than 175,000 metres under these programs.

Recent activity

In 2012, we focused on expanding the underground development on both the 530 metre and 640 metre levels, northeasterly towards Zone B. We conducted a definition drilling program on McA North (1) and commenced underground drilling into Zone A in mid-2012. An exploration drift is also moving southwesterly on the 530 metre level.

In 2013, we continued advancing the underground exploration drifts in the southwest and northeast directions and focused on developing Zone 4 and areas at the southwest end of the underground mine workings. The delineation drilling program on Zone A progressed through the year.

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In 2014, we plan to continue advancing the underground exploration drifts to the southwest and northeast directions. Additional drilling is planned underground to delineate Zone A, and from surface to identify additional mineral resources in the deposit.

Sampling and analysis

Surface samples

• |  | GPS or mine site surveying instruments are used in the field to verify the location of surface drillholes.

• |  | Holes are generally drilled every 12 to 25 metres, on sections that are 50 to 200 metres apart. Drilled depths average 670 metres.

• |  | Vertical holes generally intersect mineralization at angles of 25 to 45 degrees, resulting in true widths being 40 to 70% of the drilled width. Angled holes usually intercept it perpendicularly, giving true width.

• |  | All holes are radiometrically probed.

• |  | A geologist examines the surface drillhole core in the field, determines its overall characteristics, including mineralization, logs the information, and takes samples that have noteworthy alteration, structures and radiometric anomalies.

• |  | Basement sampling procedures depend on the length of the interval sampled, and attempts are made to avoid having samples cross lithological boundaries.

• |  | All core with radioactivity greater than a set threshold is split and sampled for assay.

• |  | We measure the uranium grade by assaying core. Core recovery is generally considered excellent with some local exceptions. The quality and representativeness of the surface drillhole samples is adequate for estimating mineral resources and mine planning, but we often validate surface drillhole results against underground drilling results in the same vicinity.

Underground samples

• |  | Holes are drilled in stations 30 metres apart. Each station is drilled with three fans of holes, covering 10 metres across the deposit.

• |  | Uranium grade is calculated from the adjusted radiometric probe readings. Radiometric probing is at 0.1 metre spacing in radioactive zones and 0.5 metre spacing in unmineralized zones. The drillhole fans give the gamma probes representative access across the entire deposit.

• |  | For a small portion of the assay data we obtain, which we use to estimate mineral resources, we assay core to determine the U3O8 content past the probe limit of a hole, or to provide correlation samples to compare against a probed interval. In these cases, we log the core, photograph it, and then sample it for uranium analysis. We sample the entire interval instead of splitting the core. This provides very high-quality samples in these areas.

• |  | Core recovery in these areas can be excellent to poor.

• |  | The quality and representativeness of the underground drillhole samples is adequate for estimating mineral resources and mine planning.

Analysis

We record the following for each sample:

• |  | hole number, date and name

• |  | sample number

• |  | from and to intervals and length

• |  | recovered length

• |  | range of radioactivity

• |  | weight

• |  | core diameter

• |  | rock type, alteration, and mineralization.

We place each sample in a plastic bag and write its number on the bag. We place the bags in a metal or plastic shipping drum, which is scanned by the radiation department and shipped to the Saskatchewan Research Council (SRC) in Saskatoon for analysis.

SRC personnel:

• |  | verify the sample information

• |  | sort the samples by radioactivity

• |  | dry, crush and grind them in secure facilities or in the main laboratory, if they have minimal radioactivity

• |  | dilute the samples and carry out a chemical analysis

• |  | prepare and analyse a quality control sample with each batch

• |  | analyse one of every 40 samples in duplicate.

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Quality control

A data and quality assurance coordinator on staff is responsible for reviewing the quality of geochemical data received from laboratory contractors. The coordinator reviews the analyses provided by the lab using the results of standard reference materials as a benchmark, and, together with project geologists, determines whether it is necessary to reassay.

We use several quality control measures and data verification procedures:

• |  | enter surveyed drillhole collar coordinates and hole deviations in the database, display them in plan views and sections and visually compare them to their planned location

• |  | visually validate core logging information on plan views and sections, and verify it against photographs of the core or the core itself

• |  | compare downhole radiometric probing results with core radioactivity and drilling depth measurements

• |  | validate uranium grade based on radiometric probing with sample assay results, when available

• |  | compare the information in the database against the original data, including paper logs, deviation survey films, assay certificates and original probing data files.

Since 2000, we have regularly compared information collected from production activities, such as freezeholes, raisebore pilot holes, radiometric scanning of scoop tram buckets and mill feed sampling, to the drillhole data.

Quality assurance and quality control for underground drillhole information focuses on ensuring quality probing results. We do this by:

• |  | checking the calibration of probes before using them

• |  | visually monitoring the radiometric measurements

• |  | periodically duplicating probe runs.

We also compare the probing results with the core measurements, and have an experienced geologist at the mine site or in Saskatoon visually inspect the radiometric profile of each hole. Reconciling the model with mine production is a very good indicator that estimated grades in the block model accurately reflect the mined grades.

Sample security

All samples collected from McArthur River are prepared and analysed under the close supervision of a qualified geoscientist at the SRC, which is a restricted access laboratory licensed by the CNSC.

We store and ship all samples in compliance with regulations. We consider it unlikely that samples are tampered with because of the high grade of the ore and the process used: the core is scanned immediately after it is received at a sample preparation laboratory and grade is estimated at that point.

Accuracy

We are satisfied with the quality of data obtained from surface exploration and underground drilling at McArthur River and consider it valid for estimating mineral resources and mineral reserves. This is supported by the fact that for the last five years, we have accurately estimated tonnage, grade and pounds to within less than 6%.

Mineral reserve and resource estimates

Please see page 75 for our mineral reserve and resource estimates for McArthur River.

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Uranium – operating properties

|  | Rabbit Lake The Rabbit Lake operation, which opened in 1975, is the longest operating uranium production facility in North America, and the second largest uranium mill in the world.
Location |  | Saskatchewan, Canada
Ownership |  | 100%
End product |  | uranium concentrates
ISO certification |  | ISO 14001 certified
Mine type |  | underground
Estimated mineral reserves |  | 20.3 million pounds (proven and probable)
|  | average grade U3O8 – 0.56%
Estimated mineral resources |  | 20.2 million pounds (indicated)
|  | average grade U3O8 – 0.80%
|  | 9.0 million pounds (inferred)
|  | average grade U3O8 – 0.58%
Mining method |  | vertical blasthole stoping
Licensed capacity |  | mill: maximum 16.9 million pounds per year; currently 11 million
Total production 1975 to 2013 |  | 194.2 million pounds
2013 production |  | 4.1 million pounds
2014 forecast production |  | 4.1 million pounds
Estimated decommissioning cost |  | $203 million

Business structure

We own 100% of Rabbit Lake.

Permits

We need three key permits to operate the Rabbit Lake mining and milling complex:

• |  | Uranium Mine Operating Licence from the CNSC – expires on October 31, 2023

• |  | Approval to Operate Pollutant Control Facilities from the Saskatchewan Ministry of the Environment – expires on October 31, 2016

• |  | Water Rights Licence and Approval to Operate Works – valid for an undefined term (from the Saskatchewan Watershed Authority).

Production

2013 production was 4.1 million pounds U3O8.

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Operations

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

Exploration

In 2011, we received regulatory approval to begin exploration–related development and drilling on a new zone (Powell Zone) located about 650 metres northeast of the existing mine workings. In 2013, we continued to make progress on the related development work.

We extended our underground drilling reserve replacement program into 2013, testing beneath existing zones as well as to the east and northeast of the current mine workings, including the Powell Zone.

We plan to continue our underground drilling reserve replacement program in areas of interest east and northeast of the mine in 2014, both at depth and along the strike of the Collins Bay fault.

Tailings

We expect the mill to have the capacity to handle tailings from milling ore from Eagle Point until approximately 2018 (based on expected ore tonnages and milling rates).

In 2014, we are continuing to evaluate options to expand the existing tailings management facility capacity to support mining of existing reserves at Eagle Point, and provide additional tailings capacity to process ore from other potential sources. Depending on the chosen option, we may need an environmental assessment and regulatory approval to proceed with any increase in capacity.

Site reclamation

We are proceeding with our multi-year, site wide reclamation plan. We spent over $1.2 million in 2013 to reclaim facilities that are no longer in use, and plan to spend $0.5 million in 2014.

Mill renewal

We have been working on upgrades to the Rabbit Lake mill and associated facilities since 2006:

• |  | 2006 – reduced mill effluent concentrations of uranium

• |  | 2008 – replaced the mill-distributed control system and improved the mill’s secondary containment

• |  | 2009 – reduced mill effluent concentrations of molybdenum and selenium

• |  | 2010 – replaced the converter and heat recovery equipment in the acid plant

• |  | 2011 – replaced the three acid plant towers in the acid plant and completed ongoing upgrades to mill processing equipment and tanks

• |  | 2012 – continued the replacement of mill and site electrical infrastructure

• |  | 2013 – rebuilt mill sulfur furnace.

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Uranium – operating properties

|  | Smith Ranch-Highland We operate Smith Ranch and Highland as a combined operation. Each has its own processing facility, but the Smith Ranch central plant currently processes all the uranium, 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 mineral reserves |  | Smith Ranch-Highland:
|  | 5.2 million pounds (proven and probable), average grade U3O8 – 0.09%
|  | North Butte-Brown Ranch:
|  | 3.8 million pounds (proven and probable), average grade U3O8 – 0.08 %
Estimated mineral resources |  | Smith Ranch-Highland:
|  | 21.8 million pounds (measured and indicated), average grade U3O8 – 0.06%
|  | 7.9 million pounds (inferred), average grade U3O8 – 0.05%
|  | North Butte-Brown Ranch:
|  | 10.8 million pounds (indicated), average grade U3O8 – 0.07%
|  | 0.8 million pounds (inferred), average grade U3O8 – 0.06%
Mining method |  | in situ recovery (ISR)
Licensed capacity |  | wellfields: 3 million pounds per year
|  | processing plants: 5.5 million pounds per year including Highland mill
Total production 2002 to 2013 |  | 17.6 million pounds
2013 production |  | 1.7 million pounds
2014 forecast production |  | 2.0 million pounds
Estimated decommissioning cost |  | $202 million (US)

Business structure

We own 100% of Smith Ranch-Highland through a wholly owned subsidiary.

See our 2013 MD&A for more information.

2013 ANNUAL INFORMATION FORM Page 33

Uranium – operating properties

|  | Crow Butte Crow Butte was discovered in 1980 and began production in 1991. It is the first uranium mine in Nebraska, and is a significant contributor to the economy of northwest Nebraska.
Location |  | Nebraska, US
Ownership |  | 100%
End product |  | uranium concentrates
ISO certification |  | ISO 14001 certified
Estimated mineral reserves |  | 2.3 million pounds (proven)
|  | average grade U3O8 – 0.11%
Estimated mineral resources |  | 14.6 million pounds (measured and indicated)
|  | average grade U3O8 – 0.27%
|  | 2.9 million pounds (inferred)
|  | average grade U3O8 – 0.12%
Mining method |  | in situ recovery (ISR)
Licensed capacity |  | 2.0 million pounds per year
(processing plant and wellfields) |  |
Total production 2002 to 2013 |  | 9.0 million pounds
2013 production |  | 0.7 million pounds
2014 forecast production |  | 0.6 million pounds
Estimated decommissioning cost |  | $44 million (US)

Business structure

We own 100% of Crow Butte through a wholly owned subsidiary.

See our 2013 MD&A for more information.

2013 ANNUAL INFORMATION FORM Page 34

Uranium – operating properties

|  | Inkai Inkai is a very significant uranium deposit, located in Kazakhstan. There are two production areas (blocks 1 and 2) and an exploration area (block 3). The operator is Joint Venture Inkai Limited Liability Partnership, which we jointly own (60%) with Kazatomprom (40%). Inkai is one of our three material uranium properties.
Location |  | South Kazakhstan
Ownership |  | 60%
End product |  | uranium concentrates
Certifications |  | BSI OHSAS 18001
|  | ISO 14001 certified
Estimated mineral reserves |  | 50.4 million pounds (proven and probable)
(our share)(1) |  | average grade U3O8 – 0.07%
Estimated mineral resources |  | 28.3 million pounds (indicated)
(our share)(2) |  | average grade U3O8 – 0.08%
|  | 146.3 million pounds (inferred)
|  | average grade U3O8 – 0.05%
Mining method |  | in situ recovery (ISR)
Licensed capacity |  | 5.2 million pounds per year
(wellfields) |  | (our share 3.0 million pounds per year)
Total production 2008 to 2013 |  | 12 million pounds
(our share) |  |
2013 production |  | 3.0 million pounds
(our share) |  |
2014 forecast production (100% basis) |  | 5.2 million pounds (our share 3.0 million pounds)
Estimated mine life |  | 2030 (based on current licence term)
Estimated decommissioning cost |  | $14 million (US)
(100% basis) |  |

(1) | Our share of uranium in the mineral reserves 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%).

(2) | Our share of uranium in the mineral resources 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.

2013 ANNUAL INFORMATION FORM Page 35

Business structure

Inkai is a Kazakhstan limited liability partnership between two companies:

• |  | Cameco – 60%

• |  | JSC NAC KazAtomProm (Kazatomprom) – 40% (a Kazakhstan Joint Stock Company owned by the Republic of Kazakhstan)

History

1976-78 |  | • |  | Deposit is discovered
|  | • |  | Exploration drilling continues until 1996
1979 |  | • |  | Regional and local hydrogeology studies begin
|  | • |  | Borehole tests characterize the four aquifers within the Inkai deposit (Uvanas, Zhalpak, Inkuduk and Mynkuduk)
1988 |  | • |  | Pilot test in the northeast area of block 1 begins, lasts 495 days and recovers 92,900 pounds of uranium
1993 |  | • |  | First Kazakhstan estimates of uranium reserves for block 1
1996 |  | • |  | First Kazakhstan estimates of uranium reserves for block 2
|  | • |  | Kazakhstan regulators registers Inkai, a joint venture among us, Uranerzbergbau-GmbH and KATEP
1997-1998 |  | • |  | Kazatomprom is established
|  | • |  | KATEP transfers all of its interest in the Inkai joint venture to Kazatomprom
1998 |  | • |  | We acquire all of Uranerzbergbau-GmbH’s interest in the Inkai joint venture, increasing our interest to 66 2/3%
|  | • |  | We agree to transfer a 6 2/3% interest to Kazatomprom, reducing our holdings to a 60% interest
1999 |  | • |  | Inkai receives a mining licence for block 1 and an exploration licence for blocks 2 and 3 from the government of Kazakhstan
2000 |  | • |  | Inkai and the government of Kazakhstan sign a subsoil use contract (called the resource use contract), which covers the licences issued in 1999 (see above)
2002 |  | • |  | Test mining operations at block 2 begins
2005 |  | • |  | Construction of ISR commercial processing facility at block 1 begins
2006 |  | • |  | Complete test mine expansion at block 2
2007 |  | • |  | Sign Amendment No.1 to the resource use contract, extending the exploration period at blocks 2 and 3
2008 |  | • |  | Commission front half of the main processing plant in the fourth quarter, and begin processing solution from block 1
2009 |  | • |  | Sign Amendment No. 2 to the resource use contract, which approves the mining licence at block 2, extends the exploration licence for block 3 to July 13, 2010, and requires Inkai to adopt the new tax code and meet the Kazakhstan content thresholds for human resources, goods, works and services
|  | • |  | Commission the main processing plant, and started commissioning the first satellite plant
2010 |  | • |  | Receive regulatory approval for commissioning of the main processing plant
|  | • |  | File a notice of potential commercial discovery at block 3
|  | • |  | Receive approval in principle for the extension of the block 3 exploration licence for a five-year appraisal period that expires July 2015, and an increase in annual production from blocks 1 and 2 to 3.9 million pounds (100% basis)
2011 |  | • |  | Receive regulatory approval for commissioning of the first satellite plant
|  | • |  | Sign Amendment No. 3 to the resource use contract, which extends the exploration licence for block 3 to July 2015 and provides government approval to increase annual production from blocks 1 and 2 to 3.9 million pounds (100% basis)
|  | • |  | Sign a memorandum of agreement with Kazatomprom to increase annual production from blocks 1 and 2 from 3.9 million pounds to 5.2 million pounds (100% basis)
2012 |  | • |  | Sign a memorandum of agreement with Kazatomprom setting the framework to increase annual production from blocks 1 and 2 to 10.4 million pounds (100% basis), to extend the term of Inkai’s resource use contract through 2045 and to co-operate on the development of uranium conversion capacity, with the primary focus on uranium refining rather than uranium conversion. For more information on this agreement see page 40.
2013 |  | • |  | Sign Amendment No. 4 to the resource use contract, which provides government approval to increase annual production from blocks 1 and 2 to 5.2 million pounds (100% basis)

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Technical report

This project description is based on the project’s technical report: Inkai Operation, South Kazakhstan Oblast, Republic of Kazakhstan, dated March 31, 2010 (effective December 31, 2009) except for some updates that reflect developments since the technical report was published. The report was prepared for us in accordance with NI 43-101, by or under the supervision of two Cameco qualified persons within the meaning of NI 43-101. The following description has been prepared under the supervision of Alain G. Mainville, P. Geo., Ken Gullen P. Eng., and Lawrence Reimann, P. Eng. They are all qualified persons within the meaning of NI 43-101, but are not independent of us.

For information about environmental matters, see Safety, Health and the Environment starting on page 84.

For a description of royalties payable to the government of Kazakhstan on the sale of uranium extracted from orebodies within the country and taxes, see pages 99 and 100.

The conclusions, projections and estimates included in this description are subject to the qualifications, assumptions and exclusions set out in the technical report, except as such qualifications, assumptions and exclusions may be modified in this AIF. We recommend you read the technical report in its entirety to fully understand the project. You can download a copy from SEDAR (sedar.com) or from EDGAR (sec.gov).

About the Inkai property

Location

The Inkai mine is located in the Suzak District of South Kazakhstan Oblast, Kazakhstan near the town of Taikonur, 370 kilometres north of the city of Shymkent and 125 kilometres east of the city of Kyzyl-Orda.

Accessibility

The road to Taikonur is the primary road for transporting people, supplies and uranium product to and from the mine. It is a paved and gravel road that crosses the Karatau Mountains. Railroad transportation is available from Almaty to Shymkent, then northwest to Shieli, Kyzyl-Orda and beyond. A rail line also runs from the town of Taraz to a Kazatomprom facility to the south of Taikonur.

Licences

Inkai holds the rights to three contiguous licence blocks, blocks 1, 2 and 3, based on the licences it has received and its resource use contract with the Kazakhstan government. Inkai has to meet certain obligations to maintain these rights. See pages 41 and 42 for more information.

Setting

Inkai lies in the Betpak Dala Desert, which has an arid climate, minimal precipitation and relatively high evaporation. The average precipitation varies from 130 to 140 millimetres per year, and 22 to 40% of this is snow. The surface elevation within the Inkai property boundary ranges from 130 to 250 metres above mean sea level.

The area also has typically strong winds. The prevailing winds are northeast. Dust storms are not uncommon. The major water systems in the area include the Shu, Sarysu and Boktykaryn rivers.

Geology

The deposit is sub-divided into two regions: the Sandy-brackish intercontinental deltas of the Shu and Sarysu rivers, and the Betpak Dala plateau.

The geology of south-central Kazakhstan is comprised of a large relatively flat basin of Cretaceous to Neogene age continental clastic sedimentary rocks. The Cretaceous-Cainozoic Chu-Sarysu basin extends for more than 1,000 kilometres from the foothills of the Tien Shan Mountains on the south and southeast sides, and merges into the flats of the Aral Sea depression to the northwest. The basin is up to 250 kilometres wide, bordered by the Greater Karatau Mountains on the southwest and the Chu-Ili uplift and Central Kazakhstan uplands on the northeast. It is composed of gently dipping to nearly flat lying fluvial-derived unconsolidated sediments composed of inter-bedded sand, silt, and local clay horizons.

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The Cretaceous-Cenozoic sediments host several stacked and relatively continuous, sinuous “roll-fronts”, or oxidation-reduction (redox) fronts hosted in the more porous and permeable sand and silt units. There are several uranium deposits and active ISR uranium mines at these regional oxidation roll-fronts, developed along a regional system of superimposed mineralization fronts.

The Inkai deposit is hosted within the Inkuduk and Mynkuduk formations, which are made up of feldspathic sandstones or sub-arkoses, typically containing 50 to 60% quartz, 10 to 15% feldspar, and 5 to 10% clay. The redox boundary can be readily recognised in core by a distinct colour change from gray on the reduced side to yellowish stains on the oxidized side, stemming from the oxidation of pyrite to limonite. In cross-section, the redox boundary is often “C” shaped forming the classic “roll-front”. The sands have a high horizontal permeability.

Mineralization

Seven mineralized zones have been identified on blocks 1 and 2, including three zones in the Mynkuduk horizon and four zones in the Inkuduk horizon.

Mineralization includes sooty pitchblende (85%) and coffinite (15%). The pitchblende occurs as micron-sized globules and spherical aggregates. The coffinite occurs as small crystals. Both uranium minerals are commonly associated with pyrite, and occur in pores on interstitial materials like clay minerals, as films around and in cracks within sand grains, and as pseudomorphic replacements of rare organic matter.

Most of the mineralization in block 1 is in the Mynkuduk horizon, of Turonian age, which unconformably overlays Permian argillites. Made up of fine to medium sands with occasional layers of clay or silt, this horizon is at a depth of 500 metres. The surface projection of the Mynkuduk horizon has an overall length of about 31 kilometres at an average width of 160 metres. The lower part of the Inkuduk horizon, which sits above the Mynkuduk horizon, is also locally mineralized.

In block 2, mineralization is mainly in the Middle and Lower Inkuduk horizons, between 350 and 420 metres below the surface. For the Inkuduk horizons, the overall length is about 66 kilometres at an average width of 160 metres.

Block 3 update

Exploration work on the northern flank (block 3) of the Inkai deposit has identified extensive mineralization hosted by several horizons in the lower and middle parts of the Upper Cretaceous stratigraphic level and traced along 25 kilometres from block 2 of the Inkai deposit in the southwest through to the Mynkuduk deposit in the northeast. This discovery requires further assessment of its commercial viability. In February 2010, Inkai filed a notice of the discovery with regulators.

In April 2011, Inkai received government approval to amend the block 3 licence to provide for a five-year appraisal period, which expires July 2015, to carry out delineation drilling, uranium resource estimation, construction and operation of a test leach facility and to complete a feasibility study. In June 2011, Inkai paid a $2.7 million (US) commercial discovery bonus to the state. In 2011, Inkai continued delineation drilling, began infrastructure development and completed engineering for a test leach facility for the block 3 assessment program.

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

In 2013, Inkai:

• |  | completed exploration drilling

• |  | continued construction of the test leach facility and test wellfields

• |  | started work on an appraisal of mineral potential according to Kazakhstan standards.

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In 2014, Inkai expects to:

• |  | complete construction of the test leach facility and test wellfields

• |  | start operation of the test wellfields and uranium production with the test leach facility

• |  | complete a preliminary appraisal and continue to work on a final appraisal of mineral potential according to Kazakhstan standards.

About the Inkai operation

Inkai is a developed mineral property with sufficient surface rights to meet future mining operation needs for the current mineral reserves.

Licences

Inkai needs a number of licences to operate the Inkai mine:

• |  | Licence Series AY 1370D, April 20, 1999, expires in 2024

For uranium extraction in block 1 (16.6 square kilometres)

• |  | Licence Series AY 1371D, April 20, 1999

For exploration and uranium extraction in block 2 (230 square kilometres) (expires in 2030) and for exploration in block 3 (240 square kilometres) (expires in 2015).

Other material licences

• |  | Licence for performance of activity related to handling of radioactive substances (including extraction and processing of natural uranium) (issued January 18, 2010 by the Kazakhstan Ministry of Energy and Mineral Resources (MEMR)) and renewed on July 31, 2012 by the Ministry of Industry and New Technologies (MINT))

• |  | Licence for operation of mining production and mineral raw material processing (issued December 23, 2009 by the MEMR)

• |  | Licence for transportation of radioactive substances within the territory of the Republic of Kazakhstan (issued November 18, 2008 by the MEMR)

• |  | Licence for dealing with radioactive wastes (issued July 12, 2012 by MINT).

These licences are all currently in force and have an indefinite term. Inkai’s material environmental permits are described on page 42.

Infrastructure

Block 1 |  | Block 2 |  | Block 3
• main processing plant, which includes a product recovery, drying and packaging facility • administrative office, shops, garage, laboratory, emergency response building, low-level radioactive waste and domestic landfills, engineering and construction offices • a camp for 400 employees • catering and leisure facilities |  | • satellite processing plant that produces uranium loaded ion exchange resin • office, small shops, and a food services facility Inkai is expanding the satellite processing plant. |  | Inkai is constructing a test leach plant and associated facilities.

Water, power and heat

Groundwater wells provide sufficient water for all planned industrial activities. Shallow wells on site have potable water for use at the camp. The site is connected to the Kazakh power grid. Operations continue throughout the year despite cold winters (lows of -35°C) and hot summers (highs of +40°C).

Employees

Taikonur has a population of about 450 people who are mainly employed in uranium development and exploration. Whenever possible, Inkai hires personnel from Taikonur and surrounding villages.

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Mining method

Inkai uses conventional and well-established ISR technology. It has a very efficient process for uranium recovery, developed after extensive test work and operational experience. The process involves five major steps:

• |  | leach the uranium in-situ with sulphuric acid-based lixiviate solution

• |  | recover it from solution with ion exchange resin (takes place at both main and satellite processing plants)

• |  | precipitate it with hydrogen peroxide

• |  | thicken, dewater, and dry it

• |  | package it as U3O8 (yellowcake) in drums.

The process requires large quantities of sulphuric acid because there are relatively high levels of carbonate in the ore. There were no interruptions to Inkai’s sulphuric acid supply during 2013 and supply was sufficient to acidify all wellfields as planned. The supply of sulphuric acid has historically been tight in Kazakhstan, although the 2012 start-up of a new sulphuric acid plant is encouraging. Given the importance of sulphuric acid to Inkai’s mining operations and shortages in previous years, we continue to closely monitor its availability. Our production may be less than forecast if there is a shortage.

Production

Total processing plant production |  | Based on current mineral reserves, we expect Inkai to produce a total of 74.4 million pounds U3O8 (100% basis, recovered by the processing plant).
Average annual processing plant production |  | The processing plant has the capacity to produce at an annual rate of 5.2 million pounds per year (100% basis) depending on the grade of the production solution. Inkai is expanding the existing satellite plant capacity in order to support this production rate even at a lower grade.

Production increases

In April 2011, Inkai received government approval to produce 3.9 million pounds per year (100% basis).

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

In December 2013, Inkai received government approval to produce 5.2 million pounds per year (100% basis).

Uranium conversion project and doubling production update

In 2012, we entered into a memorandum of agreement (2012 MOA) with our joint venture partner Kazatomprom setting out a framework to:

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

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

Kazatomprom is pursuing a strategic objective to develop uranium processing capacity in Kazakhstan to complement its leading uranium mining operations. The 2012 MOA builds on the non-binding memorandum of understanding signed in 2007 which sought to align the annual production increase with the development of uranium conversion capacity. Kazatomprom’s primary focus is now on uranium refining, which is an intermediate step in the uranium conversion process.

We expect to pursue further expansion of production at Inkai at a pace measured to market opportunities. We are continuing to work on an assessment of the production increase, and in December 2013, we also completed the first draft of a prefeasibility study (PFS) for the potential construction of a uranium refinery in Kazakhstan. Cameco and Kazatomprom will determine if a feasibility study is justified based on the outcome of the refinery PFS. Advancement to the feasibility stage will require government approvals for the transfer of our proprietary uranium refining technology from Canada to Kazakhstan. A nuclear co-operation agreement between Canada and Kazakhstan was signed in 2013, providing the international framework necessary for applying to the two governments for the required licences and permits.

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Sales

Under Kazakhstan’s transfer pricing law (which went into effect on January 1, 2009), sales are based on the current uranium spot price. Inkai has forward uranium sales contracts with each of its joint venture partners – us and Kazatomprom. These contracts are currently in effect and both entities are in the process of negotiating new agreements with Inkai.

Funding

We have a loan agreement with Inkai whereby we funded Inkai’s project development costs. As of December 31, 2013, there was $103 million (US) of principal outstanding on the loan. In 2013, Inkai paid $2.7 million (US) in interest on the loan and repaid $30 million (US) of principal.

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

We are also currently advancing funds for Inkai’s work on block 3. As of December 31, 2013, the block 3 loan principal amounted to $118 million (US).

Payback

Payback for us is expected to be achieved during 2015, on an undiscounted pre-tax basis, including all prior costs.

Resource use contract

In 2000, Inkai and the government of Kazakhstan signed the resource use contract, which covers the licences issued in 1999. Inkai has to meet the obligations under these licences and the resource use contract to maintain its rights to blocks 1, 2 and 3.

In 2007, Inkai and the relevant government authority signed Amendment No.1 to the resource use contract to extend the exploration period at blocks 2 and 3.

In 2009, Inkai and the relevant government authority signed Amendment No. 2 to the resource use contract, which:

• |  | extended the exploration period for block 3 to July 13, 2010

• |  | approves mining at block 2

• |  | combines blocks 1 and 2 for mining and reporting purposes

• |  | requires Inkai to adopt the new tax code that took effect January 1, 2009

• |  | requires Inkai to adopt current Kazakh legal and policy requirements for subsoil users to procure goods, works and services under certain prescribed procedures and foster greater local content

• |  | prescribes Kazakh employment: over the life of the resource use contract, 100% of the workers, at least 70% of engineering and construction staff and at least 60% of the management staff must be Kazakh.

In 2011, Inkai and the relevant government authority signed Amendment No. 3 to the resource use contract which:

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

• |  | amends the block 3 licence for a five-year appraisal period to July 2015 to carry out delineation drilling, uranium resource estimation, construction and operation of a test leach facility, and to complete a feasibility study.

In December 2013, Inkai and the relevant government authority signed Amendment No. 4 to the resource use contract which approves an increase to annual production from blocks 1 and 2 to 5.2 million pounds (100% basis).

Work programs

Inkai is required to follow the work program appended to the resource use contract, which applies to mining operations over the life of the mine. To comply with the new subsoil law, Inkai developed a life of mine work plan and submitted it to the relevant government authority who approved it in April 2011 as part of the approval of Amendment No. 3 to the resource use contract (see Project documentation on page 43). An updated work program was submitted to the relevant government authority in 2012 in support of the Amendment No. 4 application and was approved in December 2013.

Environment

Inkai has to comply with environmental requirements during all stages of the project, and develop an environmental impact assessment for examination by a state environmental expert before making any legal, organizational or economic decisions that could have an effect on the environment and public health.

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Under Kazakhstan law, Inkai needs an environmental permit to operate. Inkai has a permit for environmental emissions and discharges, valid until December 31, 2016 and an emissions permit for drilling activities, valid until December 31, 2016. Inkai also holds water permits.

Insurance

Inkai carries environmental insurance, as required by the resource use contract.

Decommissioning

Inkai’s decommissioning obligations are largely defined by the resource use contract. It has deposited the required contributions into a separate bank account as security to ensure it will meet its obligations. Contributions are capped at $500,000 (US). Inkai has funded the full amount.

Under the resource use contract, Inkai must submit a plan for decommissioning the mine to the government six months before mining activities are complete. It developed a preliminary decommissioning plan to estimate total decommissioning costs, and updates the plan every five years, or when there is a significant change at the operation that could affect decommissioning estimates. The preliminary decommissioning estimate is $14 million (US).

Groundwater is not actively restored post-mining in Kazakhstan. See page 87 for additional details.

Kazakhstan government and legislation

Subsoil law

The principal legislation governing subsoil exploration and mining activity in Kazakhstan is the Subsoil Use Law dated June 24, 2010, which took effect July 7, 2010 (the subsoil law). It replaces the Law on the Subsoil and Subsoil Use, dated January 27, 1996, as amended (the old law).

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 Kazakhstan government interprets the national security exemption broadly.

The subsoil law defines the framework and procedures connected with the granting of subsoil rights, and the regulation of the activities of subsoil users. The subsoil, including the mineral resources it contains, belongs to the state. Resources brought to the surface belong to the subsoil user, unless otherwise provided by contract. The state has pre-emptive and approval rights with some exceptions (for example, for inter-group transfers), if a subsoil user transfers its subsoil rights or if there is a transfer (direct or indirect) of an ownership interest in a subsoil user.

Subsoil rights go into effect when a contract with the relevant government authority is finalized. The subsoil user is given, among other things, the exclusive right to conduct mining operations, to build production and social facilities, to freely dispose of its share of production and to negotiate extensions of the contract.

Until March 12, 2010, the Kazakhstan Ministry of Energy and Mineral Resources (MEMR) was designated as the “competent authority” under the old law. The Kazakhstan Ministry of Industry and New Technologies replaced it, and is the current competent authority under the subsoil law. We refer to the competent authority as the relevant government authority.

To date, the new subsoil law has not had a significant impact on Inkai, however, we continue to assess the impact. Some of the general impact is described below:

Stabilization clause

The general stability provision has been changed in the subsoil law. Under the old law, changes in legislation that worsened the position of the subsoil user did not apply to resource use contracts signed before the changes were adopted.

Under the new subsoil law, contracts are only protected from changes in legislation if the changes worsen the commercial position of the subsoil user. The subsoil law expands the list of exceptions from stabilization to include taxation and customs regulation. These are in addition to exceptions in the old law for defence, national security, environmental protection and health.

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.

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Amendment No. 2 to the resource use contract eliminated the tax stabilization provision that applied to Inkai.

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

Transfer of subsoil rights and pre-emptive rights

The subsoil law strengthens the state’s control over transactions involving subsoil rights and the direct and indirect ownership interests in a subsoil user.

Like the old law, transfers of subsurface rights, transfers of shares (interests) in subsoil users and the grant of security over subsurface rights require consent of the relevant government authority. The new subsoil law expands the list of transactions that require consent and also spells out in more detail the circumstances, documentation and information that must accompany the request for consent. It also contains a new provision requiring notification to the relevant government authority within five business days of completion of the transaction.

Similar to the old law, the state has a priority right on terms not worse than those offered by other buyers.

Failing to obtain the state’s waiver of its pre-emptive right or the consent of the relevant government authority or to provide the completion notification, are grounds for the state to invalidate a transfer.

Dispute resolution

The dispute resolution procedure in the subsoil law does not specifically disallow international arbitration. Instead it says that if a dispute related to a resource use contract cannot be resolved by negotiation, the parties can resolve the dispute according to the laws of Kazakhstan and international treaties ratified by the Republic of Kazakhstan.

The resource use contract allows for international arbitration. We believe the subsoil law does not affect this right.

Contract termination

Under the subsoil law the relevant government authority can terminate a contract before it expires, if a subsoil user does not fix more than two breaches of its obligations under the contract or the project documents within a specific period.

Under the old law, the relevant government authority could terminate a contract if the subsoil user materially breached its obligations established by the contract or work program.

Under the resource use contract, if Inkai materially breaches its obligations, the relevant government authority has to notify Inkai of the breach and provide a reasonable period to fix it before it can terminate the contract. We believe that the terms of the resource use contract should continue to apply unless the state seeks to apply the national security exception to stabilization.

Local content

Subsoil users must procure goods, works and services in compliance with the subsoil law. Procurement is carried out through a specially created register of the goods, works and services and of the entities (producers) providing them. Subsoil users must give preference to local producers, as long as the goods, works and services comply with applicable standards. The subsoil law also allows a statutory tender commission, which oversees tender procedures, to conditionally discount local producers’ bids by 20% relative to foreign bidders. This new local content provision applies to Inkai.

Project documentation

Subsoil users who received subsoil rights before the subsoil law was introduced were required to:

• |  | develop new project documentation to be approved by July 7, 2011

• |  | develop a new work program in accordance with the project documentation to be approved by January 7, 2012.

Inkai submitted the required documentation and received approval of the new life of mine work program as part of the April 14, 2011 approval of Amendment No. 3 to the resource use contract.

The subsoil law repealed the previous requirement for annual work plans. Instead, expected exploration and/or production volumes for each year will now be set out in the new work program. Inkai revised its work program to support the application to increase the annual production rate to 5.2 million pounds (100% basis).

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Strategic deposits

On August 19, 2009, 231 blocks, including all three of Inkai’s blocks, were prescribed as strategic deposits under the Governmental Resolution On Determination of the List of Subsoil (Deposit) Areas having Strategic Importance.

Under the subsoil law, if any actions by a subsoil user relating to a strategic deposit leads to a change in the economic interests of the state that creates a threat to national security, the relevant government authority has the right to demand a change to a contract that will restore the economic interests of the state. The parties have to agree on and make the change within a specific time period, or the relevant government authority can unilaterally terminate the contract.

Currency control regulations

In 2009, specific amendments to existing currency regulations were adopted. These amendments are aimed at preventing possible threats to the economic security and stability of the Kazakh financial system. The President of Kazakhstan was granted the power to establish a special currency regime that can:

• |  | require foreign currency holders to deposit a certain portion of their foreign currency interest free with a resident Kazakhstan bank or the National Bank of Kazakhstan

• |  | require the permission of the National Bank of Kazakhstan for currency transactions

• |  | restrict overseas transfers of foreign currency.

While the special currency regime has not been imposed, it has the potential to prevent Kazakh companies, like Inkai, from being able to pay dividends to their shareholders abroad or repatriating any or all of its profits in foreign currency. It can also impose additional administrative procedures, and Kazakh companies could be required to hold a portion of their foreign currency in local banks.

Exploration, drilling and estimates

We did not do any exploration drilling in blocks 1 and 2, and relied instead on historic data to estimate mineral reserves and resources.

Exploration

Historical drilling

• |  | Historical drilling at Inkai included 4,898 holes in blocks 1 and 2, and 510 in block 3.

• |  | Drilling was vertical, on a grid at prescribed density of 3.2 to 1.6 kilometre line spacing and 200 to 50 metre (3.2-1.6 kilometres x 200-50 metres) hole spacing. Additional drilling at grids of 800-400 x 200-50 metres and 200-100 x 50-25 metre grid increased the level of geological knowledge and confidence.

• |  | Vertical holes were drilled with a triangular drill bit for use in unconsolidated formations down to a certain depth and the rest of the holes were cored.

• |  | JSC Volkovgeology, a subsidiary of Kazatomprom, compiled the data for block 1 of the Inkai deposit as well as some of the data for block 2 to produce a report in 1991.

Exploration drilling

• |  | Inkai’s exploration and mineral resource evaluation department oversees exploration, including the strategic direction of the drilling program and management of contractors. Inkai has retained a contractor, JSC Volkovgeology, to direct and coordinate day-to-day drilling activities, and to ensure drilling quality, core recovery, surveying, geological logging, sampling, assaying and daily data processing.

• |  | Inkai had drilled a total of 4,295 exploration holes in block 3 as of the end of December 2013 (510 historic holes drilled before 2006, 45 in 2006, 90 in 2008, 456 in 2009, 1,008 in 2010, 494 in 2011, 683 in 2012 and 1,009 in 2013). All drilling conducted on grids of 400 by 50 metre and larger were cored with the core recovery of at least 70% in at least 70% of the drillholes, whereas the infill drillholes in 200 by 50 metre drilling patterns consist of predominately coreless drillholes, in compliance with the requirements of the State Reserve Commission of the Kazakh Republic.

• |  | In addition, a total of 53 hydrogeological test wells were drilled between 2010 and 2012 and a further 26 holes were drilled in 2013.

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Recent activity

• |  | The first phase of the drilling program from 2006 through 2009 was focused on drilling on an 800 x 50 metre grid pattern in the southwestern part of block 3. Also, the mineralization trends were followed along the northwestern border using sparser (800 to 1600 x 100 to 200 metre) drilling patterns.

• |  | The second phase of the drilling program from January to October 2010 was aimed at developing an 800 x 50 metre infill drilling grid pattern throughout the mineralized trend identified along the northwestern border, as well as the trend developed along the southern border.

• |  | The third phase of drilling started in October 2010 and continued throughout 2011, 2012, and 2013. Progressively tightening drilling grids (from 800 x 50 metre to 400 x 50 metre to 200 x 50 metre) were used to delineate mineralization in the southwestern and western parts of block 3.

• |  | Hydrogeological testing work (one well and multiwell aquifer pump tests) was conducted in 2010, 2011 and 2012 in the southwestern, western and central parts of block 3 to establish the hydrogeological characteristics of the aquifers of the hosting mineralized horizons, as well as their relationship to the surrounding aquitards and other aquifers. These hydrogeological characteristics and relationships are geotechnical parameters important for the ISR method of mining.

• |  | Results of exploration and delineation:

| • |  | traced the presence of mineralization throughout block 3 with greater certainty. There was a significant increase in the extent of mineralization in many places, compared to results of predecessors, which were based on sparser historical drilling grids.

| • |  | encountered more complex morphology of the mineralized zones of block 3

| • |  | used the mineralization delineation from 800 x 50 metre and 200 x 50 metre drilling grids in block 3 to form a preliminary estimate of the mineralization for most of the area covered

| • |  | led to a preliminary estimate of the mineralization on the southwestern corner of block 3, which was reviewed and approved by the State Reserve Commission

| • |  | confirmed the need for additional drilling to close off mineralization zones and better define their morphology and continuity

| • |  | Inkai has drilled a total of 154 technological wells (monitoring, injection and production wells) on the two sites identified for conducting ISR tests in two separate horizons (Inkuduk and Mynkuduk).

Sampling and analysis

Sampling

• |  | Detailed sampling procedures guide the sampling interval within the mineralization. Holes are drilled on progressively tightening grids: 3.2 to 1.6 kilometre x 200-50 metre, 800-400 metre x 200-50 metre and 200-100 metre x 50-25 metre. When core recoveries are higher than 70% and radioactivity greater than 40 micro-roentgen per hour, core samples are taken at irregular intervals of 0.2 to 1.2 metres. Sample intervals are also differentiated by barren or low permeability material.

• |  | The drillholes are nearly vertical and the mineralized horizons are almost horizontal, so the mineralized intercepts represent the true thickness of the mineralization.

• |  | Inkai’s geophysical crews survey the drillholes, logging radiometric, electrical (spontaneous potential and resistivity), caliper and deviation data. For greater accuracy, they collect downhole data only from open or uncased holes.

• |  | Sampling is done sectionally from half of the core, which is divided along its axis and cleared from the clay envelope. The average core sample length is 0.4 metres.

• |  | The split core is tested for grainsize and carbonate content.

• |  | Since gamma probing of the drillholes is used to estimate mineral resources, assays from core sampling are used only when core recovery is at least 70%, for correlation.

• |  | Core recovery is generally considered to be acceptable given the unconsolidated state of the mineralized material.

Analysis

We carried out a data verification process to validate the historic Kazakh mineral resource and reserve estimate. This included:

• |  | studying and coding all 1,294 drillholes on the JSC Volkovgeology cross sections

• |  | sampling and assaying all drillhole core that could be recovered for uranium and radium content (and according to the drill logs, this recovery was very good)

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• |  | recording the location of each sample and its assay results on the drillhole log (referred to as a passport).

Quality control

• |  | Our geoscientists, including a qualified person as such term is defined in NI 43-101, have witnessed core handling, logging and sampling used at the Inkai mine and consider the methodologies to be very satisfactory and the results representative and reliable.

• |  | Geologists with Inkai, JSC Volkovgeology, the State Reserves Commission and Cameco, have validated the current database a number of times. Our geologists consider it relevant and reliable.

• |  | The findings are supported by results of the leach tests, recent production, and drilling results on block 2 and exploration drilling in block 3.

• |  | The exchange of digital drillhole information between Inkai and us allows all information to be available for our review.

Sample security

Inkai’s current sampling process follows the strict regulations imposed by the Kazakhstan government, and includes the highest level of security measures, quality assurance and quality control. We have not been able to locate the documents describing sample security for historic Kazakhstan exploration on blocks 1, 2 and 3, but we believe the security measures taken to store and ship samples were of the same high quality.

Accuracy

We consider the historic Kazakhstan exploration data adequate and reliable for estimating mineral reserves and resources, based on the 2003 and 2007 validation of Kazakhstan estimated uranium reserves for blocks 1 and 2 (see sampling and analysis). We consider the exploration data from Inkai’s exploration program at block 3 reliable for estimating mineral reserves and resources.

Mineral reserve and resource estimates

Please see page 75 for our mineral reserve and resource estimates for Inkai.

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Uranium – development project

|  | Cigar Lake Cigar Lake is the world’s second largest high-grade uranium deposit, with grades that are 100 times the world average. We are a 50% owner and the mine operator. Cigar Lake uranium will be milled at AREVA’s McClean Lake JEB mill. Cigar Lake, which is being developed and scheduled to begin production this year, is one of our three material uranium properties.
Location |  | Saskatchewan, Canada
Ownership |  | 50.025%
End product |  | uranium concentrates
Mine type |  | underground
Estimated mineral reserves |  | 108.4 million pounds (proven and probable)
(our share) |  | average grade U3O8 – 18.30%
Estimated mineral resources |  | 1.1 million pounds (measured and indicated), average grade U3O8 – 2.27%
(our share) |  | 49.5 million pounds (inferred), average grade U3O8 –12.01%
Mining method |  | jet boring
Target production date |  | first mine production in the first quarter of 2014 begin processing ore at the McClean Lake JEB mill by the end of the second quarter of 2014
Target annual production (our share) |  | 9 million pounds at full production (18 million pounds at full production on 100% basis)
2014 forecast production |  | 1.0 to 1.5 million pounds (2.0 to 3.0 million pounds on 100% basis)
(our share) |  |
Estimated mine life |  | 15 years (based on current mineral reserves)
Estimated decommissioning cost |  | $49 million
(100% basis) |  |

Business structure

Cigar Lake is owned by a joint venture of four companies:

• |  | Cameco – 50.025% (operator)

• |  | AREVA – 37.1%

• |  | Idemitsu Canada Resources Ltd. – 7.875%

• |  | TEPCO Resources Inc. – 5.0%

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History

1976 |  | • Canadian Kelvin Resources and Asamera Oil Corporation form an exploration joint venture, which includes the lands that the Cigar Lake mine is being built on
1977 |  | • Saskatchewan Mining Development Corporation (SMDC), one of our predecessor companies, acquires a 50% interest
1980 |  | • Waterbury Lake joint venture formed, includes lands now called Cigar Lake
1981 |  | • Deposit discovered by surface drilling – it was delineated by a surface drilling program between 1982 and 1986
1985 |  | • Reorganization of the Waterbury Lake joint venture - Cigar Lake Mining Corporation becomes the operator of the Cigar Lake lands and a predecessor to AREVA becomes the operator of the remaining Waterbury Lands • SMDC has a 50.75% interest
1987-1992 |  | • Test mining, including sinking shaft 1 to 500 metres and lateral development on 420 metre, 465 metre and 480 metre levels
1988 |  | • Eldorado Resources Limited merges with SMDC to form Cameco
1993-1997 |  | • Canadian and Saskatchewan governments authorize the project to proceed to regulatory licensing stage, based on recommendation of the joint federal-provincial panel after public hearings on the project’s environmental impact
2000 |  | • Jet boring mining system tested in waste and frozen ore
2001 |  | • Joint venture approves a feasibility study and detailed engineering begins in June
2002 |  | • Joint venture is reorganized, new joint venture agreement is signed, Rabbit Lake and JEB toll milling agreements are signed, and we replace Cigar Lake Mining Corporation as Cigar Lake mine operator
2004 |  | • Environmental assessment process is complete • CNSC issues a construction licence
2005 |  | • Development begins in January
2006 |  | • Two water inflow incidents delay development: • in April, shaft 2 floods • in October, underground development areas flood • In November, we begin work to remediate the underground development areas
2008 |  | • Remediation interrupted by another inflow in August, preventing the mine from being dewatered
2009 |  | • Remediation of shaft 2 completed in May • We seal the 2008 inflow in October
2010 |  | • We finish dewatering the underground development areas in February, establish safe access to the 480 metre level, the main working level of the mine, and backfill the 465 metre level • We substantially complete clean-up, inspection, assessment and securing of underground development and resume underground development in the south end of the mine
2011 |  | • We begin to freeze the ground around shaft 2 and restart freezing the orebody from underground and from the surface • We resume the sinking of shaft 2 and early in 2012 achieve breakthrough to the 480 metre level, establishing a second means of egress for the mine • We receive regulatory approval of our mine plan and begin work on our Seru Bay project • Agreements are signed by the Cigar Lake and McLean Lake joint venture partners to mill all Cigar Lake ore at the McClean Lake JEB mill and the Rabbit Lake toll milling agreement is terminated
2012 |  | • We achieve breakthrough to the 500 metre level in shaft 2 • We assemble the first jet boring system unit underground and move it to a production tunnel where we commence preliminary commissioning
2013 |  | • CNSC issues an eight-year operating licence • We begin jet boring in ore

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Technical report

This project description is based on the project’s technical report: Cigar Lake Project, Northern Saskatchewan, Canada, dated February 24, 2012 (effective December 31, 2011) except for some updates that reflect developments since the technical report was published. The report was prepared for us in accordance with NI 43-101, by or under the supervision of four Cameco qualified persons within the meaning of NI 43-101. The following description has been prepared by or under the supervision of C. Scott Bishop, P. Eng., Alain G. Mainville, P. Geo., and Eric Paulsen, P. Eng., Pr. Eng. They are all qualified persons within the meaning of NI 43-101, but are not independent of us.

For information about uranium sales see pages 13 to 14, environmental matters see Safety, Health and the Environment starting on page 84, and taxes see pages 97 to 99.

For a description of royalties payable to the province of Saskatchewan on the sale of uranium extracted from orebodies within the province, see page 97.

The conclusions, projections and estimates included in this description are subject to the qualifications, assumptions and exclusions set out in the technical report, except as such qualifications, assumptions and exclusions may be modified in this AIF. We recommend you read the technical report in its entirety to fully understand the project. You can download a copy from SEDAR (sedar.com) or from EDGAR (sec.gov).

About the property

Location

Near Waterbury Lake approximately 660 kilometres north of Saskatoon. The mine site is four kilometres long and six kilometres wide.

Accessibility

Access to the property is by an all-weather road and by air. Supplies are transported by truck from Saskatoon and elsewhere. There is an unpaved airstrip and air terminal east of the mine site.

Saskatoon, a major population centre south of the Cigar Lake deposit, has highway and air links to the rest of North America.

Leases

Surface lease

We acquired the right to use and occupy the lands necessary to mine the deposit under a surface lease agreement with the province of Saskatchewan. In 2011, the surface lease agreement was amended to increase the area of the surface lease to implement the proposed discharge of treated effluent to Seru Bay at nearby Waterbury Lake. In addition, the separate lease for the Cigar Lake airstrip was amalgamated into this single lease. The lease covers approximately 1,042 hectares and expires in May 2044.

We are required to report annually on the status of the environment, land development and progress on northern employment and business development.

Mineral lease

We have the right to mine the deposit under ML-5521, granted to us by the province of Saskatchewan. The lease covers 308 hectares and expires December 1, 2021. We have the right to renew the lease for further 10-year terms.

Mineral claims

A mineral claim gives us the right to explore for minerals and to apply for a mineral lease. There are 25 mineral claims (Nos. S-106540 to 106564), totaling 92,740 hectares, adjoining the mineral lease and surrounding the site. The mineral claims are in good standing until 2023.

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Climate

The climate is typical of the continental sub-arctic region of northern Saskatchewan. Summers are short and cool even though daily temperatures can sometimes reach above 30°C. The mean daily temperature for the coldest month is below -20°C, and winter daily temperatures can reach below -40°C.

Setting

The deposit is 40 kilometres inside the eastern edge of the Athabasca basin in northern Saskatchewan. The topography and environment are typical of the taiga forested lands in the Athabasca basin. This area is covered with 30 to 50 metres of overburden. Vegetation is dominated by black spruce and jack pine. There is a lake known as “Cigar Lake” above the portion of the deposit that has inferred resources.

Geology

The deposit is at the unconformity contact between rock of the Athabasca Group and underlying lower Proterozoic Wollaston Group metasedimentary rocks. The Key Lake, McClean Lake and Collins Bay deposits all have a similar structural setting. While Cigar Lake shares many similarities with these deposits (general structural setting, mineralogy, geochemistry, host rock association and the age of the mineralization), it is distinguished from other similar deposits by its size, very high grade, and the high degree of clay alteration.

Cigar Lake’s geological setting is similar to McArthur River’s: the sandstone, which overlays the deposit and basement rocks, is water-bearing, with large volumes of water at significant pressure. Unlike McArthur River, however, the deposit is flat lying.

Mineralization

The Cigar Lake deposit is approximately 1,950 metres long, 20 to 100 metres wide, and ranges up to 13.5 metres thick, with an average thickness of about 5.4 metres. It occurs at depths ranging between 410 to 450 metres below the surface.

The deposit has three distinct styles of mineralization:

• |  | high-grade mineralization at the unconformity

• |  | fracture controlled, vein-like mineralization higher up in the sandstone

• |  | fracture controlled, vein-like mineralization in the basement rock.

Most of the uranium metal is in the high-grade mineralization at the unconformity, which has massive clays and high-grade uranium concentrations. This is the only economically viable style of mineralization, considering the selected mining method and ground conditions.

About the operation

Cigar Lake is a development project which is scheduled to begin production this year with sufficient surface rights to meet future mining operation needs for the current mineral reserves.

Permits

Please see pages 57 and 58 for more information about regulatory approvals for Cigar Lake.

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Infrastructure

Surface facilities are 490 metres above sea level. The site includes:

• |  | an underground mine with two shafts

• |  | gravel airstrip and air terminal

• |  | waste rock stockpiles

• |  | water containment and treatment ponds and treatment plant

• |  | a freshwater pump house

• |  | a powerhouse

• |  | electrical substations

• |  | fuel and propane supply, storage and distribution facilities

• |  | a freeze plant

• |  | a construction camp

• |  | a temporary administration building

• |  | an employee residence

• |  | an ore slurry load out facility.

The current surface lease is sufficient to accommodate personnel, access to water, airport, site roads and other necessary buildings and infrastructure.

The underground workings are confined to a small portion of the area of the mineral lease.

Water, power and heat

Waterbury Lake, which is nearby, provides water for the industrial activities and the camp. The site is connected to the provincial electricity grid, and it has standby generators in case there is an interruption in grid power.

Cigar Lake operates throughout the year despite cold winter conditions. During the winter, we use propane-fired burners to heat the fresh air necessary to ventilate the underground workings.

Employees

Employees are recruited first from communities in the area, then from major Saskatchewan population centres, like Saskatoon and then from outside the province.

Mining method

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

Orthogonal View of Underground Development and Mineralized Zones Looking Northwest

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Bulk freezing

The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. We will freeze the ore zone and surrounding ground in the area to be mined to prevent water from entering the mine and to help stabilize weak rock formations. To manage our risks and meet our production schedule, the area being mined must meet specific ground freezing requirements before we begin jet boring. Bulk freezing reduces but does not eliminate the risk of water inflows.

In the past, bulk freezing was done exclusively from underground. In 2010, however, we tested and began to implement an innovative surface freeze strategy.

We will use surface freezing to support the rampup period and underground freezing for the longer term development of the mine. This is our hybrid freezing approach. In 2011, we restarted freezing a portion of the orebody using holes from underground that had been completed prior to the 2006 inflow, along with initiating freezing in a group of the newly completed surface freezeholes. Through 2012 and 2013, we continued to drill freezeholes from the surface, expanded the surface freezing infrastructure and put the new freezeholes into operation to ensure frozen ore is available for future production years.

In 2011, we used freezing around shaft 2 to support the sinking. By early 2012, we broke through on the 480 metre level and by mid-2012, we broke through on the 500 metre level.

Jet boring

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

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

• |  | collecting the ore and water mixture (slurry) from the cavity and pumping it to the ore storage sumps, 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

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

• |  | starting the process again with the next cavity.

This is a non-entry method, which means mining is carried out from headings in the basement rock below the deposit, so employees are not exposed to the ore. This mining approach is highly effective at managing the radiation levels workers may be exposed to. Combined with ground freezing and the cuttings collection system, jet boring should reduce radiation exposure to acceptable levels that are below regulatory limits.

In September 2013, we announced that we had identified additional underground work that would delay jet boring in ore. After the work was completed, we jetted the first ore cavity in December 2013.

Although we have successfully demonstrated the jet boring mining methods in trials, this method has not been proven at full production. Test mining trials have been completed on a limited number of cavities, including one in waste and one in ore in 2013, that may not be representative of the deposit as a whole. As we ramp up production, there may be some technical challenges, which could affect our production plans including, but not limited to, variable or unanticipated ground conditions, ground movement and cave-ins, water inflows and variable dilution, recovery values and mining productivity. There is a risk that the rampup to full production may take longer than planned and that the full production rate may not be achieved on a sustained and consistent basis. A comprehensive commissioning and startup plan is underway with the objective of achieving a successful startup and on-going operations. We are confident we will be able to solve challenges that may arise, but failure to do so would have a significant impact on our business.

In 2012, we assembled the first jet boring system unit underground and have moved it to a production tunnel where we:

• |  | began preliminary commissioning and system testing

• |  | installed temporary infrastructure to support testing in waste rock.

In 2013, we assembled the second jet boring system unit and completed our staged commissioning program for the jet boring system units, including jetting of a waste and an ore cavity.

Our mining plan requires four jet boring system units. We currently have two units and a third unit has been ordered and manufactured. We have an agreement with a supplier to manufacture and supply one additional jet boring system unit. There is a risk that the rampup to full production at Cigar Lake may take longer than planned if the manufacture or delivery of the one additional unit does not take place as scheduled. As part of our startup plan noted above, we are working with our supplier to assure timely delivery of these units. The third unit is expected to arrive at Cigar Lake in the first quarter of 2014.

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Mine development

There are two main levels in the mine: the 480 and 500 metre levels. Both levels are located in the basement rocks below the unconformity. The 480 metre level provides access to the production area below the orebody and is typically more than 25 metres below the ore zone. The main underground processing and infrastructure facilities are located on this level. The 500 metre level is accessed via a ramp from the 480 metre level. The 500 metre level provides for the main ventilation exhaust drift for the mine, the mine dewatering sump and additional processing facilities. All construction required for initial production has been completed and commissioning of these systems is nearly complete.

Mine development for both construction and operation has used three basic development systems: drill and blast with conventional ground support, NATM (New Austrian Tunneling Method), and MDS (mine development system), a 5.1 metre diameter full face tunnel boring machine, which installs a precast concrete tunnel lining for ground support. No MDS development was done in 2012 or 2013. Geotechnical drilling and analysis of ground conditions is completed prior to confirming permanent infrastructure locations.

We have previously observed some areas of spalling and cracking on a short section of concrete segments that were installed using the mine development system (MDS) in 1999. One area was refitted with a yielding liner in 2013 and will be monitored, but is considered no longer to be a concern. A few of these areas are continuing to weaken. The damage observed in these areas typically includes spall damage on the shoulders and cracking across the crown segments, particularly around the freeze pipes. We have installed screen and rockbolts through the segments as temporary works/measures designed to protect personnel from falling debris and to maintain the integrity of the tunnels. Monitoring of these tunnels is ongoing and long-term solutions are being engineered.

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. See Rehabilitating the mine below.

Processing

Cigar Lake ore slurry will be processed in two steps:

High density ore slurry – The ore slurry produced by the jet boring mining system will be pumped to Cigar Lake’s underground crushing, grinding and thickening facility. The resulting finely ground, high density ore slurry will be pumped to surface storage tanks, thickened and loaded into truck mounted containers like the ones used at McArthur River.

Processing – The containers of ore slurry will be trucked to AREVA’s McClean Lake JEB mill, 70 kilometres to the northeast for processing. See Toll Milling Agreement below for a discussion of this arrangement.

Tailings

Cigar Lake site does not have a tailings management facility. The ore will be processed at the McClean Lake JEB mill. See Toll Milling Agreement below for a discussion of the McClean Lake JEB tailings management facility.

Waste

The waste rock piles are separated into three categories:

• |  | clean rock – will remain on the mine site for use as aggregate for roads, concrete backfill and future site reclamation

• |  | mineralized waste (>0.03% U3O8) – will be disposed of underground at the Cigar Lake mine

• |  | waste with acid-generating potential – temporarily stored on engineered lined pads. It will be transported to the McClean Lake facility for permanent disposal.

Water discharged from the mine has historically been treated and released to Aline Creek. In 2011, we received approval to change the discharge location to Seru Bay (see page 58). Construction was completed in 2012. Operating approvals from the CNSC and the province of Saskatchewan were granted in 2013. We began discharging treated water to Seru Bay in August 2013.

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Production

We expect to bring the mine into production in the first quarter of 2014, with processing of Cigar Lake ore at the McClean Lake JEB mill expected to begin by the end of the second quarter of 2014. The mining plan is designed to extract all of the current mineral reserves. The following is a general summary of the production schedule guideline and parameters on a 100% basis:

Total mill production |  | • 213.5 million pounds of U3O8, based on an overall milling recovery of 98.5% • Full annual production of 18 million pounds of U3O8
Total mine production |  | • 537 thousand tonnes of ore
Average annual mine production |  | • 100 to 140 tonnes per day during peak production, depending on ore grade
Average mill feed grade |  | • 18.3% U3O8

We expect Cigar Lake to produce between two million and three million packaged pounds from the mill (100% basis) in 2014. Based upon our commissioning and rampup experience, we will adjust our plans as necessary to allow us to reach our full production rate of 18 million pounds (100% basis) by 2018.

To meet our production schedule, the area being mined must meet specific ground freezing requirements before we begin jet boring.

We have divided the orebody into production panels, and will have one jet boring mining unit operating in a panel. At least four production panels need to be frozen at one time to achieve the full production rate of 18 million pounds of U3O8 per year. At full production, two jet boring machines will be working at a time, while the other two are being moved, set up, in the backfill cycle or on maintenance.

Payback

Payback for us, excluding all 2011 and prior costs as sunk costs, is expected to be achieved during 2018, on an undiscounted pre-tax basis.

Costs

As of December 31, 2013, we had:

• |  | invested about $1.1 billion for our share of the construction costs to develop Cigar Lake

• |  | expensed about $86 million for our share of remediation expenses

• |  | expensed about $100 million for our share of standby costs

• |  | expensed about $102 million to begin commissioning.

In August 2013, we announced that our share of the total capital cost for Cigar Lake was expected to increase between 15% and 25% as a result of scope changes, increased costs at the mine and mill, and the inclusion of some capital costs that will be incurred subsequent to the mining of the first ore that were not included in our previous estimate. Our total share of the capital cost for this project is now about $1.3 billion (previously $1.1 billion) since we began development in 2005. In order to bring Cigar Lake into production in 2014, we estimate our share of capital expenditures will be about $130 million, including $100 million on modifications to the McClean Lake JEB mill. Additional expenditures of about $35 million will be required at the McClean Lake JEB mill in 2015 in order to continue ramping up to full production. Our share of standby charges until production is achieved this year are estimated to be about $15 million.

Our expectations and plans regarding Cigar Lake, including forecasts of production, costs, mine life and payback are forward-looking information, and are based specifically on the assumptions and risks listed below, and the assumptions and the material risks discussed on pages 2 and 3.

Assumptions

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

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

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• |  | there are no labour disputes or shortages

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

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

• |  | our expectation that we will be able to obtain the additional jet boring system unit we require on schedule

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

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

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

Material risks

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

• |  | ground movements and cave-ins

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

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

• |  | sufficient tailings facility capacity is not available

• |  | our mineral reserves estimate is not reliable

• |  | our development, mining or production plans for Cigar Lake are delayed or do not succeed for any reason, including technical difficulties with the jet boring mining method or freezing the deposit to meet production targets, technical difficulties with the McClean Lake JEB mill modifications or commissioning or milling Cigar Lake ore or our inability to acquire any of the required jet boring equipment.

Reclamation and financial assurances

In 2002, our preliminary decommissioning plan for Cigar Lake was approved by the CNSC and the Saskatchewan Ministry of Environment. We revised this plan and the accompanying preliminary decommissioning cost estimate when we renewed our federal licence in 2008. We revised this plan and the accompanying preliminary decommissioning cost estimate again when we received our operating licence in 2013. These documents include our estimated decommissioning costs up to the end of the construction of the mining facility.

We, along with our joint venture partners, are in the process of updating the letters of credit posted as financial assurances with the government of Saskatchewan, to cover the amount in the 2013 preliminary decommissioning cost estimate ($49 million).

The reclamation and remediation activities associated with waste rock and tailings at the McClean Lake JEB mill are covered by the plans and cost estimates for this facility.

Water inflow and mine rehabilitation

Cigar Lake Water inflow incidents

From 2006 through 2008, the Cigar Lake project suffered several setbacks as a result of three water inflow incidents. The first occurred in April of 2006 resulting in the flooding of the then partially completed shaft 2. The two subsequent incidents involved inflows in the mine workings connected to shaft 1 and resulted in flooding of the mine workings completed to that point in time.

We developed and successfully executed recovery and remediation plans for both the shaft 2 inflow and the 2 inflows experienced in the shaft 1 workings. This culminated in the resumption of sinking of shaft 2 in the first half of 2011 and the successful break through to the 480 metre level of the main mine workings in early 2012 and the commencement and completion of underground remediation and restoration of the shaft 1 workings in 2010 and 2011.

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Rehabilitating the mine

Through 2010 and 2011, we developed a comprehensive plan and successfully proceeded with remediation to restore the underground workings at Cigar Lake. This involved inspecting the mine and completing any additional remedial work to protect it from an inflow or significant ground failure (for example, determining if additional reinforcement was required in higher risk areas). The work to secure the mine was completed in 2011.

With successful re-entry to main mine working achieved in early 2010, a comprehensive underground rehabilitation program was implemented. The program of work involved rehabilitating the remaining lower risk areas of the mine (including 480 and 500 metre levels) and re-establishing the full mine ventilation circuit.

Some of the specific tasks included:

• |  | re-establishing the permanent refuge stations and communications

• |  | installing the emergency back-up pumping capacity

• |  | re-establishing the orebody freezing program

• |  | starting the shaft 2 freezing program

• |  | preparing areas to resume construction/development activities

• |  | replacing electrical components and equipment damaged due to flooding.

As part of securing the mine and underground rehabilitation program, detailed assessments of the underground conditions were completed which provided further input to the overall Cigar Lake design and strategy, allowing the mine plan to be further optimized.

Construction

With the mine fully secured, the underground rehabilitation program complete and regulatory requirements met, we resumed underground construction activities in 2011 that had been interrupted by the October 2006 water inflow.

Completing shaft 2

Shaft 2 was completed in 2013. Shaft 2 provides access to the 480 metre level. Shaft 2 is divided into two compartments by a central airtight partition: one compartment will serve as the main path for exhaust air from the mine and the second compartment will be used to downcast additional ventilation air as well as provide secondary egress and a number of additional services.

Increase pumping capacity

In 2010, we increased our pumping capacity to meet our standard for this project, which is to secure pumping capacity of at least one and a half times the estimated maximum inflow.

In 2012, our mine dewatering capacity increased to 2,500 m3/hr and our mine water treatment capacity increased to 2,550 m3/hr.

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

Surface construction

In 2013, we completed the construction of the remaining process related infrastructure, the site wide fire protection water main, hazmat building, site wide final grading, and the shaft 1 heater upgrade. Construction of the permanent maintenance shop and wash facility has commenced and is expected to be completed in the third quarter of 2014.

Underground development

The construction of the underground processing facility was substantially completed in 2013 including: the JBS mining infrastructure (pumps, filters, etc), Run of Mine (ROM) storage facility, crushing and grinding circuits, clarifier system, and ore slurry hoisting. The ancillary systems are substantially complete including wash facilities, shops, compressed air, electrical supply, fresh water, and recycled water systems. We also advanced underground development for future production tunnels.

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Toll milling agreement

The McClean Lake joint venture has agreed to process Cigar Lake’s ore slurry at its McClean Lake JEB mill, according to the terms in its agreement with the Cigar Lake joint venture: JEB toll milling agreement (effective January 1, 2002 and amended by a memorandum of agreement effective November 30, 2011). The McClean Lake joint venture has agreed to dedicate at the JEB mill the necessary mill capacity to process and package 18 million pounds of Cigar Lake uranium concentrate annually.

The Cigar Lake joint venture will pay a toll milling fee and its share of milling expenses.

In certain circumstances, the Cigar Lake joint venture is required to pay standby costs. As at December 31, 2013, standby costs of $100 million were expensed. The JEB mill was placed in a care and maintenance mode in July 2010.

To process Cigar Lake’s ore slurry, a number of mill modifications have been completed at the JEB mill. The McClean Lake joint venture is required to further modify and expand the JEB mill to process and package all of Cigar Lake’s current mineral reserves. In 2013, AREVA advised us that it had determined that further mill modifications were required before they could begin processing Cigar Lake ore. The Cigar Lake joint venture has agreed to pay for the capital costs for such modifications and expansion, which are estimated to be $260 million (100% basis). Construction of the expanded facility began in 2012 and is scheduled to be completed in 2015.

The McClean Lake joint venture commenced work in 2012 to optimize its tailings management facility to accommodate all of Cigar Lake’s current mineral reserves. Subject to a capped contribution of $4.6 million from the Cigar Lake joint venture, the McClean Lake joint venture is responsible for the cost to optimize its tailings management facility.

The McClean Lake joint venture is responsible for all costs of decommissioning the JEB mill. As well, the joint venture is responsible for the liabilities associated with tailings produced from processing Cigar Lake ore at the JEB mill.

Regulatory approvals

Environmental assessment

• |  | In 1995, the Cigar Lake Project, Environmental Impact Statement was submitted to the Joint Federal-Provincial review panel on Uranium Mining Developments in Northern Saskatchewan.

• |  | In 1997, the panel recommended that the project should proceed, pending identification of a suitable waste rock disposal location.

• |  | The Canadian and Saskatchewan governments both accepted the panel’s recommendation and in 1998 both government bodies approved the project in principle.

In February 2004, we submitted an environmental assessment study report for the Cigar Lake mine plan. The CNSC agreed that this report met the requirements of the Canadian Environment Assessment Act and approved proceeding with the licensing and permitting process.

Construction licence

• |  | The CNSC issued a construction licence in December 2004.

• |  | With water inflows in 2006 and 2008, the CNSC has twice extended the licence term. It expired on December 31, 2013 and has been replaced with the operating licence.

Operating licence

• |  | The CNSC issued an eight-year operating licence in June 2013.

Processing licences

• |  | In 2012, the CNSC approved an amendment to the operating licence for the McClean Lake JEB mill to process Cigar Lake ore. In 1997, the environmental impact statement for this processing was approved.

Water treatment/effluent discharge system

• |  | We designed the Cigar Lake system for both routine and non-routine water treatment and effluent discharge, and it has been approved and licensed by the CNSC and the Saskatchewan Ministry of Environment. As well, under the provincial operating approval, specific approvals to construct and/or operate relevant components of the surface infrastructure will be required.

• |  | We want to manage the potentially higher water inflow we may see during construction and operations by building infrastructure that will allow us to discharge treated water directly to Seru Bay of Waterbury Lake. In 2008, we submitted an application to the CNSC for this infrastructure that triggered a joint federal and provincial environmental assessment screening under the Canadian Environment Assessment Act. In 2011, our application was accepted and we received approval to proceed with construction. Construction and commissioning of the infrastructure was completed in 2012. Operating approvals were received from the CNSC and the province of Saskatchewan in 2013. We began discharging treated water to Seru Bay in August 2013.

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Exploration, drilling and estimates

The Cigar Lake uranium deposit was discovered in 1981 by surface exploration drilling.

We focus most of our exploration activities on mineral lease ML-5521. AREVA is responsible for exploration activity on the 25 surrounding claims. The data from the exploration program on the 25 mineral claims is not part of the database used for the estimate of the mineral resources and mineral reserves at Cigar Lake.

Surface drilling – mineral lease

A total of 748 surface holes have been drilled totaling 339,450 metres. 564 of these were drilled within the known deposit limits.

1982 – 1986 |  | A major surface drilling program delineated the deposit
1987 – 2002 |  | Drilling for geotechnical and infill holes
2007 – 2009 |  | 51 holes drilled for various geotechnical and geophysical programs
2010 |  | 45 drillholes were completed as part of delineation and geotechnical programs
2011 |  | 87 drillholes were completed as part of delineation, geotechnical and surface freezehole programs
2012 |  | 188 drillholes were completed as part of surface delineation, freezehole and hydrogeological monitoring programs
2013 |  | 154 drillholes were completed as part of the surface freezehole drilling program

In 2014, we plan to continue the surface freezehole drilling program.

Surface drilling – mineral claims

In 2006, exploration drilling confirmed the existence of unconformity style mineralization outside the mineral lease, 650 metres east of Phase 1 mineralization.

Since then, additional exploration in the area delineated a mineralized zone 350 metres in east-west strike length and 50 metres in across-strike length.

Underground drilling

Diamond drilling from underground was mainly to determine the rock mass characteristics of both mineralized and waste rock before development and mining.

1989 – 2006 |  | 132 underground diamond drillholes were drilled totaling 11,108 metres. Of these, 10 intersected the deposit. A total of 347 freeze and temperature monitoring holes were drilled from the underground workings during the construction phase. 182 of these were gamma surveyed by radiometric probing. Due to the drilling method for freezeholes, no core is available for assays. Uranium content is estimated by radiometric probing of the holes. In 2011, we developed conversion coefficients to convert the radiometric probe results to equivalent U3O8 grades. This allowed the 182 underground freezeholes to be incorporated into the Cigar Lake mineral resource model.
2007 – 2009 |  | There was no underground drilling because of flooding.
2010 – 2013 |  | 204 holes were drilled underground totaling 17,087 metres. 5 of the 204 holes were drilled from inside shaft 2, in advance of the top seal grout cover. 170 holes were drilled from the 480 metre level and the remaining 29 holes were drilled from the 500 metre level.

Underground drilling will continue to be conducted to assess ground conditions prior to development.

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Sampling and analysis

Sampling

In the early stages of exploration drilling, sampling intervals were of various lengths, up to 50 centimetres, based on geological differences in the character of the mineralization.

Starting in 1983, sampling intervals were fixed at a standard interval of 50 centimetres. All sample results have since been normalized at 50 centimetres for estimating mineral resources.

One additional 50 centimetre sample was taken from each of the upper and lower contacts of the mineralized zone, to ensure that the zone was fully sampled at the 0.10% U3O8 cut-off.

Vertical surface drillholes generally represented the true thickness of the zone since the mineralization is flat.

Samples were drawn from two areas (called phases) of the deposit:

Phase 1 – the eastern part (700 metres long by 150 metres wide)

• |  | nominal delineation drillhole fence spacing was 25-50 metres east-west by 20-25 metres north-south

• |  | the central area of Phase 1 has been further defined by 381 surface freezeholes drilled at nominal 5 metre spacing. A total of 41 of these freezeholes have been assayed sampled through the mineralized zone. The remaining 340 have been gamma probed to determine the uranium grade to be used for mineral resource estimation.

Phase 2 – the western part (1,200 metres long by 100 metres wide)

• |  | nominal delineation drillhole fence spacing was 200 metres east-west by 20 metres north-south

• |  | 30 infill drillholes were completed in 2011 as well as two additional drillholes in 2012 for select areas of the western part of the Phase 2 deposit, which reduced the average drillhole spacing to 35 metre by 25 metres and locally down to a 15 metre by 15 metre pattern. These holes have been included in the current resource estimate as drilling was completed in 2012.

All holes were core drilled and gamma probed whenever possible. Down-hole gamma surveys and hand held scintillometer surveys guided sampling of drill core for assay purposes when collected.

Analysis

• |  | More than 8,600 samples were collected from surface and underground drilling.

• |  | Starting in 1983, all drilling and sample procedures were standardized and documented. This gives us a high degree of confidence in the accuracy and reliability of results of all phases of the work.

• |  | When sampled, the entire core from each sample interval was taken for assay, except for some of the earliest sampling in 1981 and 1982. This reduced the sample bias inherent when splitting core.

• |  | Core recovery throughout the deposit has generally been very good. However, in areas of poor core recovery uranium grade determination is based on radiometric probe results.

• |  | Most underground drillholes that have intersected the mineralized zone were rotary holes for ground freezing so no core was recovered. For these holes, we have relied on radiometric results to determine the grade to be used in the mineral resource model.

• |  | Underground drillholes were sampled and gamma probed to the same standards as the surface drillholes.

Width |  | Assay |  | Density
• largest 13.5 metres • smallest 0.4 metres • average 5.4 metres |  | • highest 82.9% U3O8 • lowest 0.0% U3O8 |  | • highest 6.46 g/cm3 • lowest 1.27 g/cm3

Quality control and data verification

The quality assurance and quality control procedures used during the early drilling programs were typical for the time. The majority of uranium assays in the database were obtained from Loring Laboratories Ltd. For uranium assays over 5% U3O8, 12 standards and two blanks were run with each batch of samples and for uranium assays over 5% U3O8, a minimum of four standards were run with each batch of samples.

2013 ANNUAL INFORMATION FORM Page 59

More recent assaying at the Saskatchewan Research Council includes preparing and analysing standards, duplicates and blanks. A standard is prepared and analysed for each batch of samples and one out of every 40 samples is analysed in duplicate. To validate the core depth, the in-hole gamma survey results on core were compared at site to hand-held scintillometer surveys.

The original database, from which most of the mineral resources and mineral reserves are estimated, was compiled by previous operators. We reviewed a total of 1,286 original signed assay certificates, representing 29% of the original surface and underground drillhole results, to confirm data integrity. Additional QA/QC measures taken include:

• |  | entering surveyed drillhole collar coordinates and downhole deviations into the database and visually validating and comparing to the planned location of the holes

• |  | using a software program to check for data errors such as overlapping intervals and out of range values

• |  | comparing downhole radiometric probing results with radioactivity measurements made on the core and drilling depth measurements

• |  | validating uranium grades based on radiometric probing with sample assay results once available.

We are satisfied with the quality of data obtained from the exploration drilling program and consider it valid for estimating mineral resources and mineral reserves. Radiometrics of closely spaced underground and surface freezehole drilling have also confirmed the continuity and high grades of the ore zone.

Sample security

We do not know what historic security measures were in place when the deposit was delineated. Current core logging is carried out in the same facility used during the delineation drilling. It is well removed from the mine site and behind a locked entry gate, which prevents unauthorized access.

All samples were collected and prepared under the close supervision of a qualified geoscientist in a restricted core processing facility. The core samples are collected and transferred from the core boxes to high strength plastic sample bags then sealed. The sealed bags are then placed in steel drums and shipped under the Transport of Dangerous Goods regulations through our warehouse facilities at Cigar Lake directly to the laboratory.

We are satisfied with all aspects of sample preparation and assaying. The sampling records are meticulously documented and samples are whole core assayed to reduce bias, although some ore intersections were sawn in half for display purposes. The assaying was done to a high standard and the QA/QC procedures employed by the laboratories are adequate.

We believe that the sample security was maintained throughout the process. Furthermore, the continuity and high grade nature of the ore zone has been confirmed from radiometrics of closely spaced underground freezehole drilling.

Mineral reserve and resource estimates

Since the completion of the current mineral reserve and resource estimates, 381 surface freezeholes have been drilled in the central portion of the Phase 1 deposit. These drillholes have increased our geological knowledge of the deposit, and have provided further confidence in the grade characteristics. The incorporation of these additional drillholes into an updated mineral reserve and resource model is currently scheduled to be completed within the first six months of 2014.

Please see page 75 for our mineral reserve and resource estimates for Cigar Lake.

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Uranium – projects under evaluation

|  | Millennium Millennium is a uranium deposit in northern Saskatchewan. We are the operator.
Location |  | Saskatchewan, Canada
Ownership |  | 69.9%
End product |  | uranium concentrates
Mine type |  | underground
Estimated mineral resources (our share) |  | 53.0 million pounds (indicated) average grade U3O8 – 2.39% 20.2 million pounds (inferred) average grade U3O8 – 3.19%

Business structure

Millennium is owned by a joint venture of two companies:

• |  | Cameco – 69.9% (operator)

• |  | JCU Exploration (Canada) Co. Ltd. – 30.1%

See our 2013 MD&A for more information.

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Uranium – projects under evaluation

|  | Yeelirrie Yeelirrie is a near-surface calcrete-style deposit that is amenable to open pit mining techniques. We are the operator.
Location |  | Western Australia
Ownership |  | 100%
End product |  | uranium concentrates
Mine type |  | open pit
Estimated mineral resources |  | 127.3 million pounds (measured and indicated) average grade U3O8 – 0.16%

Business structure

Yeelirrie is owned 100% by a Cameco subsidiary.

See our 2013 MD&A for more information.

2013 ANNUAL INFORMATION FORM Page 62

Uranium – projects under evaluation

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

Business structure

Kintyre is owned by two companies:

• |  | A Cameco subsidiary – 70%

• |  | Mitsubishi Development Pty Ltd. – 30%

See our 2013 MD&A for more information.

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Exploration

In 2013, we continued our exploration strategy of focusing on our most prospective North American and Australian projects in our portfolio. Exploration is key to ensuring our long-term growth, and since 2008 we have continued to invest in exploring the land that we hold.

2013 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 $9 million on seven brownfield exploration projects, $7 million on our projects under evaluation in Australia, and $13 million for resource definition at Inkai and at our US operations.

Regional exploration

We spent about $44 million on regional exploration programs (including support costs). Saskatchewan was the largest region, followed by Australia and the United States.

PLANS FOR 2014

We plan to spend approximately 35% to 40% less on uranium exploration in 2014 as part of the reorganization of our global exploration portfolio that has allowed us to focus on our core projects in Saskatchewan under our long-term strategy.

Brownfield exploration

In 2014, we plan to spend approximately $5.2 million on brownfield exploration in Saskatchewan and Australia, with a focus on McArthur River and projects supporting Kintyre. Our expenditures on projects under evaluation are expected to total $10 million, with the largest amount spent on Inkai block 3 in Kazakhstan.

Regional exploration

We plan to spend about $25 million on 24 projects in Australia and Canada, the majority of which are at drill target stage. Among the larger expenditures planned is $6 million on the Read Lake project, which is adjacent to McArthur River in Saskatchewan.

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Fuel services – refining

|  | Blind River refinery Blind River is the world’s largest commercial uranium refinery, refining uranium concentrates from mines around the world into UO3.
Location |  | Ontario, Canada
Ownership |  | 100%
End product |  | UO3
ISO certification |  | ISO 14001 certified
Licensed capacity |  | 24 million kgU as UO3 per year (subject to the completion of certain equipment upgrades)
2013 production |  | 14.2 million kgU of UO3
Estimated decommissioning cost |  | $39 million

Markets

UO3 is shipped to Port Hope for conversion into either UF6 or UO2, or to Springfields, UK for conversion into UF6.

Production

Our Blind River refinery produced 14.2 million kgU of UO3 this year enabling our conversion business to achieve its production targets.

Inventory

Inventory of uranium concentrates has been declining compared to historic levels and continues to affect the facility’s operating schedule. In the past, there was plenty of feedstock because customers stored large inventories at the facility. Customers now hold almost no inventory as concentrates, and provide the feedstock on a just-in-time basis. We manage production to match the conversion requirements.

Capacity

In the fall of 2008, the CNSC approved the environmental assessment required to increase the licensed production to 24 million kgU per year. In December 2008, we submitted a written request to the regulator for an amendment to the licence. In February 2012, the CNSC granted an increase to our annual licensed production capacity from 18 million kgU per year as UO3 to 24 million kgU as UO3, subject to the completion of certain equipment upgrades.

Licensing

In February 2012, the CNSC granted our Blind River refinery a 10-year operating licence.

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Fuel services – conversion and fuel manufacturing

|  | Port Hope conversion services 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
Estimated decommissioning cost |  | $102 million
Cameco Fuel Manufacturing Inc. (CFM)
CFM produces fuel bundles and reactor components for CANDU reactors.
Location |  | Ontario, Canada
Ownership |  | 100%
End product |  | CANDU fuel bundles and components
ISO certification |  | ISO 9001 certified, ISO 14001 certified
Licensed capacity |  | 1.2 million kgU as UO2 as finished bundles
Estimated decommissioning cost |  | $20 million
Springfields Fuels Ltd. (SFL)
SFL is the newest conversion facility in the world. We contract almost all of its capacity through a toll-processing agreement to 2016.
Location |  | Lancashire, UK
Toll-processing agreement |  | annual conversion of 5 million kgU as UO3 to UF6
Licensed capacity |  | 6.0 million kgU as UF6 per year

Port Hope, CFM and SFL produced a total of 14.9 million kilograms of uranium in 2013.

2013 ANNUAL INFORMATION FORM Page 66

Licensing

In February 2012, the CNSC approved a five-year operating licence for the Port Hope conversion facility and a ten-year licence for CFM.

Conversion services

At its UO2 plant, Port Hope produces UO2 powder, used to make pellets for Canadian and Korean CANDU reactors and blanket fuel for light water nuclear reactors.

At its UF6 plant, Port Hope converts UO3 to UF6, and then ships it to enrichment plants primarily in the United States and Europe. There, it is processed to become low enriched UF6, which is subsequently converted to enriched UO2 and used as reactor fuel for light water nuclear reactors.

Anhydrous hydrofluoric acid (AHF) is a primary feed material for the production of UF6. We have agreements with multiple suppliers of AHF to provide us with diversity of supply.

Environment

In 2009, we completed a site-wide environmental investigation of subsurface contamination and a site-wide risk assessment to identify contaminants that could pose a potential risk to the environment. We used the results to develop an environmental management plan to mitigate potential risks. In 2010, we enhanced the plan by adding a number of groundwater retrieval wells. In 2011, we added four additional wells. The environmental management plan met expectations throughout 2012 and in 2013, discussions took place with the regulatory authorities about the effectiveness of the current approach.

Port Hope conversion facility clean-up and modernization (Vision in Motion, formerly Vision 2010)

The federal Minister of Environment approved the environmental assessment guidelines in 2009 for Vision in Motion, our project designed to clean-up the Port Hope facility to appropriate levels and modernize it. The draft environmental impact statement was submitted to the regulator in December 2010.

In December 2012, we received a positive decision on the environmental assessment for the project from Canada’s Environment Minister, which allows us to proceed with an amendment to Port Hope’s license from the CNSC, which is required to advance the project. We began the licensing process in 2013 and the process will continue in 2014.

We have completed the purchase of one piece of land and agreed to buy an additional parcel adjacent to the facility to accommodate future plans for the facility.

10-year toll conversion agreement

In March 2005, we entered into a 10-year toll-conversion agreement with British Nuclear Fuels plc (BNFL), now Springfields Fuels Ltd. (SFL). Under the agreement, SFL has agreed to convert 5 million kilograms of UO3 per year to UF6. Our Blind River facility provides the UO3, and we entered into several long-term contracts for significant volumes of conversion services provided under this agreement.

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

Labour relations

In July 2013, unionized employees at the Port Hope conversion facility accepted a new three-year collective agreement. The previous agreement expired on June 30, 2013.

Fuel manufacturing

CFM’s main business is making fuel bundles for CANDU reactors. CFM presses UO2 powder into pellets that are loaded into tubes, manufactured by CFM, and then assembled into fuel bundles. These bundles are ready to insert into a CANDU reactor core.

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Manufacturing services agreements

A substantial portion of CFM’s business is the supply of fuel bundles to BPLP and BALP. We supply the UO2 for these fuel bundles.

Labour relations

In July 2012, unionized employees at our fuel manufacturing operations in Port Hope and Cobourg, Ontario voted to accept a new three-year collective agreement. The previous agreement expired on June 1, 2012.

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NUKEM GmbH

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

Offices |  | Alzenau, Germany (Headquarters, NUKEM GmbH)
|  | Connecticut, US (subsidiary NUKEM Inc.)
Ownership |  | 100%
Activity |  | trading of uranium and uranium-related products
2013 sales |  | 8.9 million lbs U3O8
2014 forecast sales |  | 9 to 11 million lbs U3O8

On January 9, 2013, we completed the acquisition of NUKEM. On closing, we paid €107 million ($140 million (US)) and acquired its net debt of about €84 million ($111 million (US)).

In accordance with the purchase agreement, we paid additional consideration of €6,075,000 million ($7,808,000) representing a share of NUKEM’s 2012 earnings. There will not be any additional payments related to this transaction.

For more information, see our 2013 MD&A.

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Electricity

|  | Bruce Power Limited Partnership (BPLP) BPLP operates four CANDU nuclear reactors that have the capacity to provide about 15% of Ontario’s electricity.
Location |  | Ontario, Canada
Ownership |  | 31.6%
ISO certification |  | ISO 14001 certified
Expected reactor life |  | 2019 to 2022
Term of lease |  | 2018 – right to extend for up to 25 years
Generation capacity |  | 3,260 MW

Business structure

BPLP, an Ontario limited partnership, is owned by:

• |  | Cameco – 31.6%

(through our wholly owned Canadian subsidiaries, Cameco Bruce Holdings Inc. and Cameco Bruce Holdings II Inc.)

• |  | TransCanada PipeLines Limited – 31.6%

• |  | Ontario Municipal Employees Retirement System Trust – 31.6%

• |  | The Power Workers’ Union and The Society of Energy Professionals – 5.2%

History

2001 |  | • We acquire a 15% limited partnership interest in BPLP and become BPLP’s fuel manager. • BPLP enters into agreements with Ontario Power Generation Inc. (OPG) to lease and operate the Bruce A and B nuclear-powered units in southwestern Ontario. The initial lease period expires in 2018. BPLP can extend the lease for up to another 25 years. • OPG retains ownership of the units, and responsibility for decommissioning and waste management.
2003 |  | • British Energy plc sells its 79.8% limited partnership interest in BPLP to a consortium of companies, including us. • After the transaction is completed, BPLP is owned: Cameco (31.6%), TransCanada PipeLines Limited (31.6%), an Ontario Municipal Employees Retirement System trust (31.6%), and The Power Workers’ Union and The Society of Energy Professionals (5.2%). • We continue as BPLP’s fuel manager.

2013 ANNUAL INFORMATION FORM Page 70

2005 |  | • BPLP is restructured and announces a new arrangement with the Ontario government to increase output of the four Bruce A reactors, including by refurbishing and restarting two Bruce A reactors that had been removed from service. BALP is formed and subleases the four Bruce A reactors from BPLP. • BPLP receives payment for the sublease, the assets it transfers to BALP under the sublease, and for Bruce A refurbishment costs already incurred. • BPLP is responsible for the overall management of the Bruce site and continues to lease and operate the four Bruce B reactors. • We maintain our 31.6% interest in BPLP and do not participate in BALP. • BPLP pays a special distribution to its limited partners. We receive $200 million.
2014 |  | • In January, we announced the sale of our 31.6% limited partnership interest in BPLP to BPC Generation Infrastructure Trust, one of the limited partners in BPLP, for $450 million. The effective date for the sale is December 31, 2013. Under the agreements governing BPLP, the limited partners have rights of first offer upon a sale by us. Closing of the transaction is subject to completion or waiver of the right of first offer process by the other limited partners and receipt of certain regulatory and third party approvals.

About the generating facilities

Location

250 kilometres northwest of Toronto on Lake Huron.

Infrastructure

• |  | four Bruce B CANDU reactors: commissioned between 1984 and 1987 and have a combined net generating capacity of 3,260 megawatts

• |  | four Bruce A CANDU reactors: commissioned between 1977 and 1979 and have a combined generating capacity of 3,000 megawatts. These were removed from service from 1995 and 1998. In 2003 and 2004, two of them were returned to service, and these have a combined net generating capacity of 1,500 megawatts. The Bruce A1 and A2 units returned to service in 2012. They also have a combined net generating capacity of 1,500 megawatts.

Average capacity factor

86.5% in 2013, and 93.7% in 2012.

Average capacity factor is the amount of electricity the four Bruce B reactors actually produced for sale as a percentage of the amount they were capable of producing.

Capital expenditures

$237 million in 2013 (100% basis).

Employees

4,076 BPLP employees, mostly unionized. Employee costs are apportioned between BPLP and BALP.

About CANDU technology

CANDU is a pressurized-heavy-water natural-uranium power reactor designed in the 1960s by a consortium of Canadian government agencies and private industry. All commercial nuclear reactors in Canada use CANDU technology.

CANDU reactors are different from light water reactors in several ways:

• |  | they are fuelled by natural uranium (UO2)

• |  | they use deuterium oxide, or heavy water, both to slow down the fission process and to transfer heat within the reactor

• |  | they can be refuelled without being taken offline.

Despite their ability to be refueled at full power, the Bruce CANDU reactors have a higher number of outage days per year than the average for light water reactors, mainly because of the time required for maintenance and repair of pressure tubes and feeders, which light water reactors do not use.

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Shutdown systems

Every Bruce reactor has two physically separate and independent systems designed to shut down the reactor within two seconds from when the system is activated. The Bruce reactors also have an emergency core coolant injection system, which activates if a pipe breaks in the reactor coolant system, and a negative pressure containment system designed to safely contain radioactive material.

Recent operational changes

In light of the events at Fukushima-Daiichi nuclear plant in Japan in March of 2011, Bruce Power has made a number of enhancements to ensure it is prepared for external hazards.

Bruce Power has acquired five fire trucks that would pump cold water into steam generators, which cools the fuel, and into its fuel bays, where used fuel is stored, in the unlikely event that its current safety systems stop working. Two trucks are stored on site and three will be kept off-site in a safe and dry area.

Bruce Power has also acquired nine new back-up generators, with a tenth to be delivered in February 2014. All are designed to power essential safety equipment in the event power is lost to the site for an extended period of time. The generators are able to run 24 hours at 80 percent of their capacities without having to refuel. Bruce Power has also built a state-of-the-art Emergency Management Centre and is testing a number of broadcast communications methods, which will allow it to monitor on-site activities and communicate internally and externally in the event of an incident.

Unit power ratings

Bruce B units currently operate at 93% power, consistent with regulatory standards set by the CNSC. As a result of innovations this was increased over the last several years from 90%. BPLP indicates this will continue to be monitored and adjusted as needed as the asset life of the Bruce B units is safely managed.

Operating life

The Bruce B nuclear units were initially expected to operate for 30 years.

Based on a testing program and the actual operating history of the units to date, BPLP estimates the units can operate longer as a result of technological advancements and asset management activities/investments.

BPLP estimates the units will operate until:

• |  | 2022 for the Bruce B8 unit

• |  | 2019 to 2020 for the other three B units

This, however, could change as BPLP works with the OPA to put commercial arrangements in place to secure the integrated nuclear schedule for the province outlined in the Long Term Energy Plan.

Additional asset life could be secured by demonstrating that longer operating life is possible for the units and their key components such as steam generators, fuel channels and feeder pipes through inspection, analysis and maintenance activities.

Steam generators

As of December 31, 2010, BPLP had inspected all of the Bruce B steam generators and determined their present condition with a reasonable degree of certainty. An ongoing surveillance program continues across all units. BPLP believes that all of the inner tubes in the steam generators are likely to degrade, and that regular cleaning, repairs and internal modifications will continue to be carried out as part of asset management activities. BPLP has been able to demonstrate very good performance and asset management of the steam generators at Bruce B. Current estimates of steam generator life are consistent with the estimated operating lives of the units and continue to be managed as needed to align with site investment programs.

Fuel channels

Past engineering assessments have indicated that the fuel channels will last until the end of the estimated operating lives for the Bruce B units, and current inspections support this. In 2001, BPLP began a maintenance program to reposition the support springs in the fuel channels to ensure life expectancy. The support springs in the Bruce B8 unit also need to be repositioned, but this unit has tight fitting garter springs. BPLP is developing new tooling to locate and move the springs, and is now targeting to test and commission the tooling in 2014 for full deployment in 2016.

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Feeder pipes

BPLP has carried out inspections to determine the condition of the feeder pipes in the Bruce B units. Feeder pipes are part of the system that transports the heat generated by the nuclear reactor to the steam generators, using the heavy water coolant. The feeder pipes in all CANDU reactors thin and degrade to varying degrees, and this is the subject of industry studies and monitoring. The Bruce B units have degraded to a lesser extent than other CANDU units. This difference is due to a combination of lower operating stresses and, to a limited extent, their output rating. BPLP has been very effective at managing this as part of asset life management and has carried out the appropriate requirements as needed through planned maintenance activities. Feeder pipes will continue to be part of BPLP’s ongoing surveillance program.

Relationship with our fuel manufacturing and UO2 businesses

Sales to BPLP and BALP are a substantial portion of our fuel manufacturing business and an important part of our UO2 business.

Financial commitments

Our total commitment and actual exposure for financial assurances given on behalf of BPLP was $58 million at December 31, 2013. The financial assurances are guarantees in favour of OPG under the lease (as discussed below). See note 12 to the 2013 financial statements.

The BPLP partners have agreed that all future excess cash will be distributed on a monthly basis and that separate cash calls will be made for major capital projects.

Reliance on OPG

OPG provides services to BPLP, including some that are necessary for BPLP to comply with its CNSC operating licences.

The material long-term OPG services include:

• |  | services related to the supply, delivery and processing of heavy water

• |  | low level and intermediate waste storage and disposal services

• |  | collection and storage of used fuel bundles (see page 91 for more information about nuclear waste management and decommissioning).

Lease payments to OPG

Under the lease, OPG is responsible for decommissioning liabilities. These are covered by BPLP’s payments under the lease. OPG can ask for limited adjustments to the base rent every five years during the initial lease period to reflect increases in the anticipated cost of decommissioning.

In 2006, OPG completed its first five-year review and proposed an increase of $14.8 million to the annual base rate over the remaining initial term of the lease. BPLP disagreed with the proposal.

In October 2008, the matter was resolved by agreement between OPG and BPLP and the base rent was not increased. BPLP is, however, required to pay the higher base rent retroactively to when it was proposed, in any one of the following situations:

• |  | if BPLP fails to renew the lease past 2027

• |  | if a BPLP material event of default occurs under the lease prior to June 30, 2027

• |  | if BPLP terminates the lease prematurely because it is no longer economically viable to operate the facility.

In 2011, OPG completed the second five-year review of the estimated decommissioning costs. The updated estimate decreased compared to the review completed in 2006 and therefore no adjustments to the base rent were required.

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In addition to base rent, BPLP pays an annual supplemental rent of $12 million for each Bruce B operating reactor. If the annual average price of electricity exceeds $30 per megawatt hour, the supplemental rent increases to $31 million per operating reactor and increases with inflation.

In 2013, the total lease payments were $89 million.

BPLP can also terminate the lease if it is no longer economically viable to operate the facility, as long as it:

• |  | pays a lease termination fee of $175 million

• |  | pays the increase in base rent specified in the 2008 settlement with OPG

• |  | meets specified ongoing operational requirements during handover

• |  | meets specified shut-down conditions before handover.

We have guaranteed BPLP’s performance of these obligations to a maximum amount of $58 million.

Transmission System

The total capacity of all the transmission lines from the Bruce site is approximately 8,100 megawatts. There is sufficient transmission capacity to support flow away from Bruce Power during normal operating conditions.

2013 ANNUAL INFORMATION FORM Page 74

Mineral reserves and resources

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

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

We estimate and disclose mineral reserves and resources in five categories, using the definitions adopted by the Canadian Institute of Mining, Metallurgy and Petroleum, and in accordance with NI 43-101. You can find out more about these categories at cim.org.

About mineral resources

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

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

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

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

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

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

About mineral reserves

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

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

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

We use current geological models, an average uranium price of $63.75 (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%).

Qualified persons

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

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McArthur River/Key Lake |  | Cigar Lake
• Alain G. Mainville, director, mineral resources management, Cameco • David Bronkhorst, vice-president, mining and technology, Cameco • Greg Murdock, mine manager, Rabbit Lake, Cameco • Les Yesnik, general manager, Key Lake, Cameco |  | • Alain G. Mainville, director, mineral resources management, Cameco • Scott Bishop, principal mine engineer, technology group, Cameco • Eric Paulsen, chief metallurgist, technology group, Cameco
Inkai |  |
• Alain G. Mainville, director, mineral resources management, Cameco • Ken Gullen, technical director, international, Cameco • Lawrence Reimann, manager, technical services, Cameco Resources |  |

Important information about mineral reserve and resource estimates

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

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

• |  | geological interpretation

• |  | extraction plans

• |  | commodity prices and currency exchange rates

• |  | recovery rates

• |  | operating and capital costs.

There is no assurance that the indicated levels of uranium will be produced, and we may have to re-estimate our mineral reserves based on actual production experience. Changes in the price of uranium, production costs or recovery rates could make it unprofitable for us to operate or develop a particular site or sites for a period of time. See page 1 for information about forward-looking information, and page 101 for a discussion of the risks that can affect our business.

Please see page 81 for the specific assumptions, parameters and methods used for the McArthur River, Cigar Lake and Inkai mineral reserve and resource estimates.

Important information for US investors

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

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

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

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

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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.

Mineral reserves

As at December 31, 2013 (100% basis – only the second last column shows Cameco’s share)

Proven and probable (tonnes in thousands; pounds in millions)

|  |  |  | Proven |  |  | Probable |  |  | Total mineral reserves |
Property |  | Mining method |  | Tonnes |  |  | Grade %U3O8 |  |  | Content (lbs U3O8) |  |  | Tonnes |  |  | Grade %U3O8 |  |  | Content (lbs U3O8) |  |  | Tonnes |  |  | Grade %U3O8 |  |  | Content (lbs U3O8) |  |  | Cameco’s share of content (lbs U3O8) |  |  | Metallurgical recovery (%) |
Cigar Lake |  | underground |  |  | 233.6 |  |  |  | 22.31 |  |  |  | 114.9 |  |  |  | 303.5 |  |  |  | 15.22 |  |  |  | 101.8 |  |  |  | 537.1 |  |  |  | 18.30 |  |  |  | 216.7 |  |  |  | 108.4 |  |  |  | 98.5 |
Key Lake |  | open pit |  |  | 67.5 |  |  |  | 0.50 |  |  |  | 0.7 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 67.5 |  |  |  | 0.50 |  |  |  | 0.7 |  |  |  | 0.6 |  |  |  | 98.7 |
McArthur River |  | underground |  |  | 465.2 |  |  |  | 21.42 |  |  |  | 219.7 |  |  |  | 572.2 |  |  |  | 11.17 |  |  |  | 140.8 |  |  |  | 1,037.4 |  |  |  | 15.76 |  |  |  | 360.5 |  |  |  | 251.6 |  |  |  | 98.7 |
Rabbit Lake |  | underground |  |  | 43.0 |  |  |  | 0.29 |  |  |  | 0.3 |  |  |  | 1,599.1 |  |  |  | 0.57 |  |  |  | 20.0 |  |  |  | 1,642.1 |  |  |  | 0.56 |  |  |  | 20.3 |  |  |  | 20.3 |  |  |  | 97.0 |
Crow Butte |  | ISR |  |  | 928.6 |  |  |  | 0.11 |  |  |  | 2.3 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 928.6 |  |  |  | 0.11 |  |  |  | 2.3 |  |  |  | 2.3 |  |  |  | 85.0 |
Inkai |  | ISR |  |  | 1,947.1 |  |  |  | 0.08 |  |  |  | 3.6 |  |  |  | 57,742.6 |  |  |  | 0.07 |  |  |  | 84.0 |  |  |  | 59,689.7 |  |  |  | 0.07 |  |  |  | 87.6 |  |  |  | 50.4 |  |  |  | 85.0 |
North Butte-Brown Ranch |  | ISR |  |  | 925.1 |  |  |  | 0.09 |  |  |  | 1.8 |  |  |  | 1,361.9 |  |  |  | 0.07 |  |  |  | 2.0 |  |  |  | 2,287.0 |  |  |  | 0.08 |  |  |  | 3.8 |  |  |  | 3.8 |  |  |  | 80.0 |
Smith Ranch-Highland |  | ISR |  |  | 1,100.8 |  |  |  | 0.10 |  |  |  | 2.5 |  |  |  | 1,498.3 |  |  |  | 0.08 |  |  |  | 2.7 |  |  |  | 2,599.1 |  |  |  | 0.09 |  |  |  | 5.2 |  |  |  | 5.2 |  |  |  | 80.0 |
Total |  |  |  |  | 5,710.8 |  |  |  | — |  |  |  | 345.7 |  |  |  | 63,077.6 |  |  |  | — |  |  |  | 351.5 |  |  |  | 68,788.5 |  |  |  | — |  |  |  | 697.2 |  |  |  | 442.7 |  |  |  |  |

Notes

ISR - in situ recovery

Estimates in the above table:

• |  | use an average uranium price of $63.75 (US) per pound U3O8

• |  | are based on an average exchange rate of $1(US) = $1.05(Cdn)

Totals may not add up due to rounding.

We do not expect these mineral reserve estimates to be materially affected by metallurgical, environmental, permitting, legal, taxation, socio-economic, political, marketing or other relevant issues.

METALLURGICAL RECOVERY

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

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Changes this year

The table below shows the change in our share of mineral reserves for each property in 2013. The change was mostly the result of:

• |  | the mining, milling and leaching activities, which removed 24.6 million pounds from our mineral inventory

• |  | the upgrade of Zone 1 at McArthur River from Probable reserves to Proven due to completion of detailed mining plans

• |  | the conversion of mineral reserves to resources at Gas Hills due to geological reinterpretation, re-estimation, and not demonstrated profitability.

(thousands of pounds U3O8) |  | December 31, 2012 |  |  | Throughput(1) |  |  | Additions (deletions)(2) |  |  | December 31, 2013 |
Proven mineral reserves |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cigar Lake |  |  | 57,473 |  |  |  | 0 |  |  |  | 0 |  |  |  | 57,473 |
Crow Butte |  |  | 2,897 |  |  |  | (831 | ) |  |  | 204 |  |  |  | 2,270 |
Inkai |  |  | 2,937 |  |  |  | (875 | ) |  |  | 0 |  |  |  | 2,062 |
Key Lake |  |  | 590 |  |  |  | 0 |  |  |  | 32 |  |  |  | 622 |
McArthur River |  |  | 136,099 |  |  |  | (13,680 | ) |  |  | 30,908 |  |  |  | 153,327 |
North Butte – Brown Ranch |  |  | 0 |  |  |  | (351 | ) |  |  | 2,125 |  |  |  | 1,774 |
Rabbit Lake |  |  | 1,195 |  |  |  | (780 | ) |  |  | (136 | ) |  |  | 279 |
Smith Ranch-Highland |  |  | 3,035 |  |  |  | (1,776 | ) |  |  | 1,246 |  |  |  | 2,505 |
Total |  |  | 204,226 |  |  |  | (18,293 | ) |  |  | 34,379 |  |  |  | 220,312 |
Probable mineral reserves |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cigar Lake |  |  | 50,950 |  |  |  | 0 |  |  |  | 0 |  |  |  | 50,950 |
Crow Butte |  |  | 68 |  |  |  | 0 |  |  |  | (68 | ) |  |  | 0 |
Gas Hills – Peach |  |  | 2,431 |  |  |  | 0 |  |  |  | (2,431 | ) |  |  | 0 |
Inkai |  |  | 51,021 |  |  |  | (2,730 | ) |  |  | 0 |  |  |  | 48,291 |
McArthur River |  |  | 128,386 |  |  |  | (345 | ) |  |  | (29,772 | ) |  |  | 98,319 |
North Butte – Brown Ranch |  |  | 3,328 |  |  |  | 0 |  |  |  | (1,298 | ) |  |  | 2,030 |
Rabbit Lake |  |  | 21,592 |  |  |  | (3,218 | ) |  |  | 1,675 |  |  |  | 20,049 |
Smith Ranch-Highland |  |  | 3,162 |  |  |  | 0 |  |  |  | (429 | ) |  |  | 2,733 |
Total |  |  | 260,938 |  |  |  | (6,293 | ) |  |  | (32,273 | ) |  |  | 222,372 |
Total mineral reserves |  |  | 465,164 |  |  |  | (24,586 | ) |  |  | 2,106 |  |  |  | 442,684 |

Notes

(1) | Throughput corresponds to mill feed. The difference between 2013 mill feed and Cameco’s share of pounds U3O8 produced in 2013 is due to mill recovery, mill inventory and processing of low-grade material.

(2) | Additions and (deletions) come from reassessing geological data, gathering data from drilling, mining and milling, and reclassifying material as either a mineral reserve or a mineral resource as applicable.

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Mineral resources

As at December 31, 2013 (100% basis – only the last column shows Cameco’s share)

Measured and indicated (tonnes in thousands; pounds in millions)

|  |  |  | Measured |  |  | Indicated |  |  | Total measured and indicated |
Property |  | Mining method |  | Tonnes |  |  | Grade % U3O8 |  |  | Content (lbs U3O8) |  |  | Tonnes |  |  | Grade % U3O8 |  |  | Content (lbs U3O8) |  |  | Tonnes |  |  | Grade % U3O8 |  |  | Content (lbs U3O8) |  |  | Cameco’s share (lbs U3O8) |
Cigar Lake |  | underground |  |  | 18.9 |  |  |  | 1.68 |  |  |  | 0.7 |  |  |  | 25.5 |  |  |  | 2.71 |  |  |  | 1.5 |  |  |  | 44.4 |  |  |  | 2.27 |  |  |  | 2.2 |  |  |  | 1.1 |
Dawn Lake |  | open pit, underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 347.0 |  |  |  | 1.69 |  |  |  | 12.9 |  |  |  | 347.0 |  |  |  | 1.69 |  |  |  | 12.9 |  |  |  | 7.4 |
Kintyre |  | open pit |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 4,315.4 |  |  |  | 0.58 |  |  |  | 55.2 |  |  |  | 4,315.4 |  |  |  | 0.58 |  |  |  | 55.2 |  |  |  | 38.7 |
McArthur River |  | underground |  |  | 111.2 |  |  |  | 4.13 |  |  |  | 10.1 |  |  |  | 16.7 |  |  |  | 9.36 |  |  |  | 3.5 |  |  |  | 127.9 |  |  |  | 4.81 |  |  |  | 13.6 |  |  |  | 9.5 |
Millennium |  | underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,442.6 |  |  |  | 2.39 |  |  |  | 75.9 |  |  |  | 1,442.6 |  |  |  | 2.39 |  |  |  | 75.9 |  |  |  | 53.0 |
Phoenix |  | underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 152.4 |  |  |  | 15.60 |  |  |  | 52.3 |  |  |  | 152.4 |  |  |  | 15.60 |  |  |  | 52.3 |  |  |  | 15.7 |
Rabbit Lake |  | underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,152.6 |  |  |  | 0.80 |  |  |  | 20.2 |  |  |  | 1,152.6 |  |  |  | 0.80 |  |  |  | 20.2 |  |  |  | 20.2 |
Tamarack |  | underground |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 183.8 |  |  |  | 4.42 |  |  |  | 17.9 |  |  |  | 183.8 |  |  |  | 4.42 |  |  |  | 17.9 |  |  |  | 10.3 |
Yeelirrie |  | open pit |  |  | 24,013.5 |  |  |  | 0.17 |  |  |  | 92.4 |  |  |  | 12,626.5 |  |  |  | 0.13 |  |  |  | 34.9 |  |  |  | 36,640.0 |  |  |  | 0.16 |  |  |  | 127.3 |  |  |  | 127.3 |
Crow Butte |  | ISR |  |  | 1,133.1 |  |  |  | 0.24 |  |  |  | 6.0 |  |  |  | 1,354.9 |  |  |  | 0.29 |  |  |  | 8.6 |  |  |  | 2,488.0 |  |  |  | 0.27 |  |  |  | 14.6 |  |  |  | 14.6 |
Gas Hills – Peach |  | ISR |  |  | 4,558.8 |  |  |  | 0.10 |  |  |  | 9.7 |  |  |  | 5,214.7 |  |  |  | 0.11 |  |  |  | 12.2 |  |  |  | 9,773.5 |  |  |  | 0.10 |  |  |  | 21.9 |  |  |  | 21.9 |
Inkai |  | ISR |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 29,346.4 |  |  |  | 0.08 |  |  |  | 49.2 |  |  |  | 29,346.4 |  |  |  | 0.08 |  |  |  | 49.2 |  |  |  | 28.3 |
North Butte – Brown Ranch |  | ISR |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 7,245.7 |  |  |  | 0.07 |  |  |  | 10.8 |  |  |  | 7,245.7 |  |  |  | 0.07 |  |  |  | 10.8 |  |  |  | 10.8 |
Ruby Ranch |  | ISR |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 2,215.3 |  |  |  | 0.08 |  |  |  | 4.1 |  |  |  | 2,215.3 |  |  |  | 0.08 |  |  |  | 4.1 |  |  |  | 4.1 |
Ruth |  | ISR |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 1,080.5 |  |  |  | 0.09 |  |  |  | 2.1 |  |  |  | 1,080.5 |  |  |  | 0.09 |  |  |  | 2.1 |  |  |  | 2.1 |
Shirley Basin |  | ISR |  |  | 89.2 |  |  |  | 0.16 |  |  |  | 0.3 |  |  |  | 1,638.2 |  |  |  | 0.11 |  |  |  | 4.1 |  |  |  | 1,727.4 |  |  |  | 0.12 |  |  |  | 4.4 |  |  |  | 4.4 |
Smith Ranch – Highland |  | ISR |  |  | 1,783.1 |  |  |  | 0.10 |  |  |  | 4.0 |  |  |  | 14,618.1 |  |  |  | 0.06 |  |  |  | 17.8 |  |  |  | 16,401.2 |  |  |  | 0.06 |  |  |  | 21.8 |  |  |  | 21.8 |
Total |  |  |  |  | 31,707.8 |  |  |  | — |  |  |  | 123.2 |  |  |  | 82,976.4 |  |  |  | — |  |  |  | 383.3 |  |  |  | 114,684.2 |  |  |  | — |  |  |  | 506.5 |  |  |  | 391.2 |

Inferred (tonnes in thousands; pounds in millions)

Property |  | Mining method |  | Tonnes |  |  | Grade % U3O8 |  |  | Content (lbs U3O8) |  |  | Cameco’s share (lbs U3O8) |  |  | Notes ISR – in situ recovery Mineral resources do not include amounts that have been identified as mineral reserves. Mineral resources do not have demonstrated economic viability. Totals may not add up due to rounding.
Cigar Lake |  | underground |  |  | 373.4 |  |  |  | 12.01 |  |  |  | 98.9 |  |  |  | 49.5 |  |
Kintyre |  | open pit |  |  | 950.2 |  |  |  | 0.46 |  |  |  | 9.6 |  |  |  | 6.7 |  |
McArthur River |  | underground |  |  | 350.7 |  |  |  | 7.38 |  |  |  | 57.1 |  |  |  | 39.9 |  |
Millennium |  | underground |  |  | 412.4 |  |  |  | 3.19 |  |  |  | 29.0 |  |  |  | 20.2 |  |
Phoenix |  | underground |  |  | 11.6 |  |  |  | 29.80 |  |  |  | 7.6 |  |  |  | 2.3 |  |
Rabbit Lake |  | underground |  |  | 708.5 |  |  |  | 0.58 |  |  |  | 9.0 |  |  |  | 9.0 |  |
Tamarack |  | underground |  |  | 45.6 |  |  |  | 1.02 |  |  |  | 1.0 |  |  |  | 0.6 |  |
Crow Butte |  | ISR |  |  | 1,135.2 |  |  |  | 0.12 |  |  |  | 2.9 |  |  |  | 2.9 |  |
Gas Hills-Peach |  | ISR |  |  | 585.3 |  |  |  | 0.07 |  |  |  | 0.9 |  |  |  | 0.9 |  |
Inkai |  | ISR |  |  | 254,217.9 |  |  |  | 0.05 |  |  |  | 254.4 |  |  |  | 146.3 |  |
North Butte-Brown Ranch |  | ISR |  |  | 594.3 |  |  |  | 0.06 |  |  |  | 0.8 |  |  |  | 0.8 |  |
Ruby Ranch |  | ISR |  |  | 56.2 |  |  |  | 0.14 |  |  |  | 0.2 |  |  |  | 0.2 |  |
Ruth |  | ISR |  |  | 210.9 |  |  |  | 0.08 |  |  |  | 0.4 |  |  |  | 0.4 |  |
Shirley Basin |  | ISR |  |  | 508.0 |  |  |  | 0.10 |  |  |  | 1.1 |  |  |  | 1.1 |  |
Smith Ranch – Highland |  | ISR |  |  | 6,989.4 |  |  |  | 0.05 |  |  |  | 7.9 |  |  |  | 7.9 |  |
Total |  |  |  |  | 267,149.6 |  |  |  | — |  |  |  | 480.8 |  |  |  | 288.6 |  |

2013 ANNUAL INFORMATION FORM Page 79

Changes this year

The table below shows the change in our share of mineral resources for each property in 2013. The change was mostly the result of:

• |  | the addition of Yeelirrie mineral resources to our inventory

• |  | the addition of Indicated resources at Rabbit Lake from delineation drilling and conversion of Inferred resources to Indicated resources

• |  | the addition of Indicated and Inferred resources to Millennium from delineation drilling

• |  | the conversion of mineral reserves to resources at Gas Hills.

(thousands of pounds U3O8) |  | December 31, 2012 |  |  | Additions (deletions) |  |  | December 31, 2013 |
Measured mineral resources |  |  |  |  |  |  |  |  |  |  |  |
Cigar Lake |  |  | 351 |  |  |  | 0 |  |  |  | 351 |
Crow Butte |  |  | 0 |  |  |  | 6,026 |  |  |  | 6,026 |
Gas Hills – Peach |  |  | 3,372 |  |  |  | 6,319 |  |  |  | 9,691 |
McArthur River |  |  | 6,098 |  |  |  | 987 |  |  |  | 7,085 |
Shirley Basin |  |  | 304 |  |  |  | 0 |  |  |  | 304 |
Smith Ranch-Highland |  |  | 5,183 |  |  |  | (1,188 | ) |  |  | 3,995 |
Yeelirrie |  |  | 0 |  |  |  | 92,382 |  |  |  | 92,382 |
Total |  |  | 15,308 |  |  |  | 104,526 |  |  |  | 119,834 |
Indicated mineral resources |  |  |  |  |  |  |  |  |  |  |  |
Cigar Lake |  |  | 761 |  |  |  | 0 |  |  |  | 761 |
Crow Butte |  |  | 12,204 |  |  |  | (3,605 | ) |  |  | 8,599 |
Dawn Lake |  |  | 7,436 |  |  |  | 0 |  |  |  | 7,436 |
Gas Hills – Peach |  |  | 18,821 |  |  |  | (6,647 | ) |  |  | 12,174 |
Inkai |  |  | 27,967 |  |  |  | 341 |  |  |  | 28,308 |
Kintyre |  |  | 38,657 |  |  |  | 0 |  |  |  | 38,657 |
McArthur River |  |  | 2,382 |  |  |  | 27 |  |  |  | 2,409 |
Millennium |  |  | 47,650 |  |  |  | 5,390 |  |  |  | 53,040 |
North Butte – Brown Ranch |  |  | 12,341 |  |  |  | (1,500 | ) |  |  | 10,841 |
Phoenix |  |  | 15,690 |  |  |  | 0 |  |  |  | 15,690 |
Rabbit Lake |  |  | 6,423 |  |  |  | 13,825 |  |  |  | 20,248 |
Ruby Ranch |  |  | 4,078 |  |  |  | 0 |  |  |  | 4,078 |
Ruth |  |  | 2,097 |  |  |  | 0 |  |  |  | 2,097 |
Shirley Basin |  |  | 4,085 |  |  |  | 0 |  |  |  | 4,085 |
Smith Ranch-Highland |  |  | 17,756 |  |  |  | 0 |  |  |  | 17,756 |
Tamarack |  |  | 10,288 |  |  |  | 0 |  |  |  | 10,288 |
Yeelirrie |  |  | 0 |  |  |  | 34,935 |  |  |  | 34,935 |
Total |  |  | 228,636 |  |  |  | 42,766 |  |  |  | 271,402 |
Total measured and indicated mineral resources |  |  | 243,944 |  |  |  | 147,292 |  |  |  | 391,236 |

2013 ANNUAL INFORMATION FORM Page 80

(thousands of pounds U3O8) |  | December 31, 2012 |  |  | Additions (deletions)(1) |  |  | December 31, 2013 |
Inferred mineral resources |  |  |  |  |  |  |  |  |  |  |  |
Cigar Lake |  |  | 49,475 |  |  |  | 0 |  |  |  | 49,475 |
Crow Butte |  |  | 5,412 |  |  |  | (2,519 | ) |  |  | 2,893 |
Gas Hills – Peach |  |  | 1,289 |  |  |  | (415 | ) |  |  | 874 |
Inkai |  |  | 146,602 |  |  |  | (304 | ) |  |  | 146,298 |
Kintyre |  |  | 6,719 |  |  |  | 0 |  |  |  | 6,719 |
McArthur River |  |  | 39,453 |  |  |  | 403 |  |  |  | 39,856 |
Millennium |  |  | 15,600 |  |  |  | 4,643 |  |  |  | 20,243 |
North Butte – Brown Ranch |  |  | 827 |  |  |  | 0 |  |  |  | 827 |
Phoenix |  |  | 2,280 |  |  |  | 0 |  |  |  | 2,280 |
Rabbit Lake |  |  | 10,293 |  |  |  | (1,249 | ) |  |  | 9,044 |
Ruby Ranch |  |  | 167 |  |  |  | 0 |  |  |  | 167 |
Ruth |  |  | 365 |  |  |  | 0 |  |  |  | 365 |
Shirley Basin |  |  | 1,132 |  |  |  | 0 |  |  |  | 1,132 |
Smith Ranch-Highland |  |  | 6,575 |  |  |  | 1,303 |  |  |  | 7,878 |
Tamarack |  |  | 591 |  |  |  | 0 |  |  |  | 591 |
Total inferred mineral resources |  |  | 286,780 |  |  |  | 1,862 |  |  |  | 288,642 |

Note

(1) | Additions and (deletions) come from reassessing geological data, gathering data from drilling, mining and milling, and reclassifying material as either a mineral reserve or a mineral resource, as applicable.

Key assumptions, parameters and methods

McArthur River

The McArthur River mineral reserve and resource estimates were audited and validated by an independent consulting firm in 2013.

Key assumptions

• |  | Reported mineral reserves do not include amounts identified as mineral resources.

• |  | Mineral reserves have been estimated with an average allowance of approximately 20% dilution from backfill and mineralized waste mined and a mining recovery of 97.5%. Mineral resources do not include such allowances.

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

• |  | An average uranium price of $63.75 (US) per pound U3O8 with a $1.00 (US) = $1.05 (Cdn) fixed exchange rate was used to estimate mineral reserves.

Key parameters

• |  | The uranium grade is determined from assay samples where available, or by converting radiometric probing values to equivalent % U3O8 based on a correlation between radiometric counts and assay values.

• |  | Densities are determined using formulas based on density measurements of drill core and chemical assay grades.

• |  | Mineral reserves at McArthur River are estimated based on the use of raisebore, boxhole and blasthole stope mining methods combined with freeze curtains.

• |  | The production schedule assumes the current average licence limit of 18.7 million pounds U3O8 per year until 2017. Between 2018 and 2026, an average annual production of 21.5 million pounds U3O8 is forecast. Estimated production then begins to decrease in three distinct steps towards the end of the mine life.

Key methods

• |  | Mineral resources were estimated using cross-sectional method and 3-dimensional block models and mineral reserves were estimated with 3-dimensional block models.

2013 ANNUAL INFORMATION FORM Page 81

• |  | The models were created from the geological interpretation of section and plan derived from surface and underground drillhole information. Estimates of block grade and density were obtained with ordinary kriging or inverse squared distance methods.

Cigar Lake

Key assumptions

• |  | Mineral resources have been estimated using a minimum mineralization thickness of 1.0 metre and a minimum grade of 1.0% U3O8.

• |  | Mineral reserves have been estimated at a cut-off grade of 2.0% U3O8 and a minimum mineralization thickness of 1.5 metre, after calculating the diluted grade.

• |  | Mineral reserves have been estimated with an allowance of 0.5 metre of dilution material above and below the ore zone, plus 11% external dilution at 0% U3O8 and a mining recovery of 90%. Mineral resources do not include such allowances.

• |  | An average uranium price of $63.75 (US) per pound U3O8 with a $1.00 (US) = $1.05 (Cdn) fixed exchange rate was used to estimate mineral reserves.

Key parameters

• |  | Grades of U3O8 were obtained from chemical assaying of drill core and checked against radiometric probing results. In areas of poor core recovery (< 75%) or missing samples, the grade was determined from probing.

• |  | A correlation between uranium grade and density was applied where the density was not directly measured for each sample.

• |  | Mining rates are planned to vary between 100 and 140 tonnes per day during peak production at a full mill production rate of 18 million pounds of U3O8 per year based on 98.5% mill recovery.

Key methods

• |  | The geological interpretation of the orebody outline was done on section and plan views derived from drillhole information. Mineral resources and mineral reserves were estimated using a 3-dimensional block model. Ordinary kriging and inverse distance squared were used to estimate the grade and density of the different areas.

Inkai

• |  | The estimated mineral resources and reserves at Inkai are located in blocks 1 and 2. No mineral resources or reserves have been estimated for block 3.

• |  | The resource models follow the Kazakhstan State Committee of Mineral Reserves (GKZ) guide and use the Grade-Thickness (GT) estimation method on 2-dimensional blocks in plan. They were created by JSC Volkovgeology, a subsidiary of Kazatomprom which is responsible for prospecting, exploration and development of uranium deposits in Kazakhstan. We performed a validation of the Kazakh reserves estimate for block 1 in 2003, and confirmed the estimated pounds of uranium to within 2.5% of the Kazakh estimate. The Kazakh estimate was also validated by an independent consulting firm in 2005. In 2007, we and an independent consulting firm verified the block 2 Kazakh mineral reserves estimate and obtained results that were consistent with the Kazakh estimate.

• |  | Historic drilling pattern densities over blocks 1 and 2 were sufficient to satisfy the Kazakhstan State Reserve Commission requirements in defining reserves in the C2, C1 and B categories within block 1 and C2 and C1 categories within block 2.

• |  | Our reconciliation of the Kazakh classification system to the CIM standard definitions are set out in Section 6.3 (Table 6-4) of the Inkai technical report. We correlate Kazakhstan’s reserves categories B, C1 and C2 to NI 43-101 mineral resource categories of measured, indicated and inferred.

Key assumptions

• |  | Dilution and mining loss are not relevant factors because Inkai uses in situ recovery as the uranium extraction method. The recovery obtained from the in situ leaching process is included in the metallurgical recovery.

• |  | Mineral reserves have been estimated at a minimum grade-thickness of 0.130 m% U3O8.

2013 ANNUAL INFORMATION FORM Page 82

Key parameters

• |  | Grades (%U3O8) were obtained from downhole gamma radiometric probing of drillholes, checked against assay results and prompt-fission neutron probing results in order to account for disequilibrium.

• |  | An average density of 1.70 t/m3 was used, based on historical and current sample measurements.

• |  | In situ recovery production rates are planned to vary between 13,000 and 16,000 lbs U3O8 per day at a full mill production rate of 5.2 million lbs of U3O8 per year based on 85% recovery.

Key methods

• |  | The geological interpretation of the orebody outline was done on section and plan views derived from drillhole and core information.

• |  | Mineral resources and mineral reserves were estimated with the grade-thickness method using 2-dimensional block models.

Sustainable development

Companies are under growing scrutiny for the way they conduct their businesses. There has been a significant increase in stakeholder expectations for environmentally and socially responsible business practices. Rather than viewing sustainable development as an “add-on” to traditional business activity, we see it as an integral component to the way we do business. We aim to integrate sustainable development principles and practices at each level of our operations, including featuring them in our objectives and our approach to compensation.

We have developed a corporate social responsibility policy (CSR) that defines our standards and expectations for sustainable development throughout the company. Under the CSR:

| • |  | our goal is to be recognized as a leader in corporate social responsibility by proactively addressing the social, environmental and financial aspects of our business with key stakeholders; and

| • |  | we seek to integrate corporate social responsibility in our day to day business, and achieve strong performance in our four key measures of success: a safe, healthy and rewarding workplace, a clean environment, supportive communities and outstanding financial performance.

We seek to implement our CSR by including commitments based upon these four key measures of success:

Safe, healthy and rewarding workplace

We are committed to having a safe, healthy and rewarding workplace that reflects the diversity of the communities in which we operate. One of the ways we implement this commitment is through our safety, health and environment policy. See Safety, Health and Environment starting at page 84 for more information about this policy.

Clean environment

We are committed to continually improving our overall environmental performance throughout the lifecycle of our operations. See Safety, Health and Environment starting at page 84 for how we implement this commitment.

Supportive communities

We are committed to building long-lasting and trusting relationships with the communities in which we operate. One of the ways we implement this commitment is through our Five Pillar CSR Strategy, which is described below.

Outstanding financial performance

We are committed to managing our business in a way that ensures long term financial stability and profitability.

Our CSR describes further what we do to implement these commitments.

Our chief executive officer is responsible for ensuring compliance with our CSR and implementation of its supporting policies and programs.

2013 ANNUAL INFORMATION FORM Page 83

Five Pillar CSR Strategy

Over more than 25 years of operation and partnership in northern Saskatchewan, we have developed a comprehensive Five Pillar CSR Strategy aimed at ensuring the support of the communities with whom we work, all across our operations globally. The strategy is flexible and is implemented by our global operations at a local level to reflect the needs of the local communities.

While developed in part as a result of some of the socio-economic obligations that are contained in our surface lease agreements with the Saskatchewan government, the bulk of the strategy has evolved as a result of the commercial benefits we see from ensuring strong support among local communities wherever we operate. The pillars are:

1. The Workforce Development pillar delivers programming that aims to build educational and skills capacity in local communities. The goal of this pillar is to ensure that students stay in school, have the means to attend post-secondary education, and receive training to facilitate employment opportunities in our industry.

2. The Business Development pillar is designed to promote the involvement of locally-owned businesses in contracting opportunities at our operations, and to provide additional jobs, revenue streams and capacity building at the local community level. We work with local contractors in a variety of ways, including by providing updates on contracting opportunities. In northern Saskatchewan, we also have a Northern Preferred Supplier program, which gives preference to majority-owned northern companies and helps to build a long-term relationship between northern contractors and ourselves.

3. The Community Engagement pillar is designed with the objective to ensure that we secure support for our operations from local communities and satisfy the obligations placed on us by regulators and laws. While the main activities here are focused specifically on the communities in closest proximity to our operations, in northern Saskatchewan, we also ensure that the greater region is kept informed of our operations, whether it is through our yearly community tours or community focused websites.

4. The Community Investment pillar is designed to help local communities with much-needed funding for community programming and infrastructure. Through this pillar, we look to support community initiatives that are focused on youth, education and literacy, health and wellness and community development.

5. The Environmental Stewardship pillar, the most recent addition to the strategy, is designed to support our overall environmental programming. It is intended to provide communities with a voice in both the formal environmental assessment regulatory process, as well as ongoing monitoring activities.

Safety, Health and Environment

We introduced our safety, health and environment policy in 1991, and have refined our approach over the years to form our overall integrated management system: the SHEQ management system.

The SHEQ policy includes our statement of principles and identifies seven programs that comprise the SHEQ management system, which implements the policy and supports these principles.

Our principles

• |  | prevent injury, ill health and pollution

• |  | comply with and move beyond legal and other requirements

• |  | keep risks at levels as low as reasonably achievable, accounting for social and economic factors

• |  | ensure quality of processes, products and services

• |  | continually improve our overall performance.

SHEQ management system

The seven programs that comprise the SHEQ management system are as follows:

• |  | Quality management program

• |  | Safety and health management program

• |  | Radiation protection program

• |  | Environmental management program

• |  | Management system audit program

• |  | Emergency preparedness and response program

• |  | Contractor management program.

2013 ANNUAL INFORMATION FORM Page 84

We benchmark our system against those used by other companies in the mining and nuclear power generation sectors. On behalf of the board, the safety, health and environment committee oversees our SHEQ policy and programs as well as our safety and environmental performance. Our chief executive officer is responsible for ensuring the system is established and maintained across the company.

Our SHEQ management system is centralized and managed at the corporate level. It is implemented across the corporation as a whole with a focus on our operations.

The management system audit program assesses our compliance with laws, regulations, permit requirements, our SHEQ-related policies and programs, and how well the sites are managing requirements and reducing risk.

We generally conduct a SHEQ audit every 18 to 24 months at each operating site, and every 12 months at every construction or development site.

SHEQ activity at the operations focuses on consistent application of programs and procedures, and providing help with identified issues. Each of our sites is responsible for conducting internal audits to make sure their programs meet Cameco standards and comply with regulatory requirements. The SHEQ management system is also part of our program to manage environmental risks at the operations and meet the requirements of ISO 14001. All of our operating sites are ISO 14001 certified.

In 2013, we invested:

• |  | $108 million in environmental protection, monitoring and assessment programs, or 8% less than 2012 as a result of large capital projects nearing completion

• |  | $31 million in health and safety programs, or 3% more than 2012.

Spending for health and safety programs in 2014 is expected to be similar to 2013, while spending for environmental programs is expected to decrease in-line with our planned reduction in capital spending.

We had 22 reportable environmental events in 2013, compared to 28 in 2012. In addition, there were no environmentally significant incidents in 2012 or 2013.

In 2013, we achieved strong safety performance at our operations.

Focus on the environment

Our business by its nature has an impact on the environment, so environmental performance is a key area of focus for us.

Our focus in this regard is reinforced by our systematic approach to safety, health, environment and quality (SHEQ) issues. We have integrated this approach into activities at our operating properties and our planning process for major projects. We also have conceptual decommissioning plans in place for all of our operating sites.

We report our performance annually. You can find this information on our website (cameco.com) and in our sustainable development report, which is also available on our website.

Reducing our impact

We have been carrying out our long-term plan to reduce the impact we have on the environment. This includes assessing, monitoring and reducing our effect on air, water and land and optimizing the amount of energy we consume, and managing the effects of waste.

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

2013 ANNUAL INFORMATION FORM Page 85

We are maximizing the lifespan of our operating sites to limit the environmental impact of our operations, and are revitalizing the Key Lake mill (in operation for 31 years) and Rabbit Lake mill (in operation for 39 years). In doing so, we have also improved air emissions by replacing some existing facilities.

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

We work with communities who are affected by our activities to tell them what we are doing and to receive feedback and further input, to build and sustain their trust. In Saskatchewan, we participate in the Athabasca Working Group and Northern Saskatchewan Environmental Quality Committee.

In Ontario, we liaise with the community by regularly holding educational and environment-focused activities including through our Community Forum series, our major presence at the Port Hope Fair, our regular community newsletters and ongoing communication with local elected officials and community leaders.

Land

Cameco’s North American operating sites affect less than 33 square kilometres of land – a relatively small area compared to what would be required to generate the same amount of energy using other technologies.

Our current mines in northern Saskatchewan are underground mines so the impact on the surface land is minimal. We use ISR mining in the U.S. to extract uranium from underground non-potable, brackish aquifers, so the impact on the surface there is also minimal.

Water

We are continually looking to improve processes and adopt new technologies to improve how we manage process water, and the effect it has on receiving water bodies.

We have taken measures that have been successful in improving the quality of our treated effluent in northern Saskatchewan with a focus on molybdenum, selenium and uranium. Through the addition of treatment circuits at Key Lake and Rabbit Lake and optimization at McArthur River, we have achieved a 70% reduction in loadings of molybdenum to the receiving environment from these three operations. With regard to selenium loadings, those same improvements have also been effective in achieving about a 50% decrease in total loadings. We have also achieved a more than 50% decrease in uranium loadings to the environment from the three operations. Even with these achievements, we are continuing to look at how we can optimize treatment circuits and water usage, thereby improving the quantity and quality of our treated water at all of our operations.

We continually monitor the environment to verify that the improvements we made in the mill effluent treatment process are having the planned effect of reducing the impact on the receiving environment.

Fuel Services

All fuel services sites have environmental management systems that are ISO14001 registered. Continuous improvement is a key aspect of the management systems and in 2013 the fuel services division advanced its focus on improving environmental performance at all three sites. The results of work by the Uranium in Air Reduction Focus Team conducted at the Port Hope conversion facility has laid the groundwork to establish a five-year objective for reducing uranium in air emissions starting in 2014.

United States

The ISR method we use in the US involves extracting uranium from underground non-potable aquifers by dissolving the uranium with a carbonate-based water solution and pumping it to a processing facility on the surface. After mining has been completed, an ISR wellfield must be restored according to regulatory requirements. This generally involves restoring the groundwater to its pre-mining state or equivalent class of use water standard. In the US, we are not only working to improve the groundwater restoration process, but also on projects to reduce waste.

We have 10 wellfields under restoration. See pages 92 and 93 for more information.

2013 ANNUAL INFORMATION FORM Page 86

Kazakhstan

The ISR mining method we use at Inkai uses an acid in the mining solution to extract uranium from underground non-potable aquifers. The injection and recovery system is engineered to prevent the mining solution from migrating to the aquifer above the orebody, which has water with higher purity.

Kazakhstan does not require active restoration of post-mining groundwater. After a number of decommissioning steps are taken, natural attenuation of the residual acid in the mined out horizon, as a passive form of groundwater restoration, has been accepted. Attenuation is a combination of neutralization of the groundwater residual acid content by interaction with the host rock minerals and other chemical reactions which immobilize residual groundwater contaminants in the mined-out subsoil horizon. This approach is considered acceptable because it results in water quality similar to the pre-mining baseline status.

Air

The table below shows our most recent data on our greenhouse gas emissions. We follow the general guidelines outlined by the Intergovernmental Panel on Climate Change to qualify greenhouse gas emissions.

|  | 2013 |  |  | 2012 |  |  | 2011 |
Greenhouse gas emissions(1) of tonnes of CO2 equivalent (CO2e) |  |  | 555,176 | (2) |  |  | 528,319 |  |  |  | 512,790 |

Note:

(1) | Greenhouse gas emissions include carbon dioxide, methane, nitrous oxide, sulphur hexafluoride, hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs) expressed as a carbon equivalent (CO2e).

(2) | This number is a preliminary estimate and the final number will be available in our 2014 sustainable development report.

The greenhouse gas emissions have been slowly increasing since 2005. As expected, the expansion of our operations has caused increases in fuel consumption, and therefore emissions.

Port Hope

In 2011, we lowered emissions of uranium and hydrofluoric acid to the air by installing new equipment and changing the operating procedures. Our fuel services division has since focused on improving the monitoring of some emission sources and establishing a process for setting an objective for reducing uranium in air emissions.

McArthur River

McArthur River has a large refrigeration plant that produces cold brine used for freezing the area of the deposit being mined. The plant uses refrigerants, but they are not ozone-depleting chemicals that harm the earth’s atmosphere.

Cigar Lake

Cigar Lake has a large refrigeration plant that produces cold brine used for freezing certain areas of the deposit as we prepare it for mining. The plant uses refrigerants, but they are not ozone-depleting chemicals that harm the earth’s atmosphere.

Key Lake

While our current emissions meet all regulatory requirements, work is ongoing to replace the mill calciner, which is expected to reduce emissions to air from the drying and packaging of the mill’s final product.

Rabbit Lake

While our current emissions meet all regulatory requirements, substantial upgrades to the acid plant at Rabbit Lake have resulted in more than a 60% reduction in the mean SO2 stack emissions (to 85 kg/day from 300 kg/day).

Waste

Our mines and mills in northern Saskatchewan account for most of the tailings and waste rock our operations generate.

We treat the mill tailings at Rabbit Lake and Key Lake to stabilize contaminants before depositing them in tailings management facilities (in mined-out open pits near the mills).

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We divert groundwater and surface water around the tailings management facilities, monitor the water to make sure it is not impacted by the tailings, and treat it if necessary. We monitor runoff and treat water from waste rock piles as needed. We stockpile some waste rock to blend with higher grade ores. We contour other waste rock piles and revegetate them before decommissioning the site. We plan to continue to monitor groundwater after the facility has been decommissioned.

Complying with environmental regulations

Our business is required to comply with laws and regulations that are designed to protect the environment and control the management of hazardous wastes and materials. Some laws and regulations focus on environmental issues in general, and others are specifically related to mining and the nuclear sector. They change often, with requirements increasing, and existing standards are being applied more stringently. While this dynamic promotes continuous improvement, it can increase expenses and capital expenditures, or limit or delay our activities.

Government legislation and regulation in various jurisdictions establish standards for system performance, standards, objectives and guidelines for air and water quality emissions, and other design or operational requirements for the various SHEQ components of our operations and the mines that we plan to develop. In addition, we must complete an environmental assessment before we begin developing a new mine or start processing activities, or make any significant change to our operations. Once we have permanently stopped mining and processing activities, we are required to decommission and reclaim the operating site to the satisfaction of the regulators, and we may be required to actively manage former mining properties for many years.

Canada

Not only is there ongoing regulatory oversight by the Canadian Nuclear Safety Commission (CNSC), the Saskatchewan Ministry of the Environment, the Ontario Ministry of the Environment, and Environment Canada, but there is also public scrutiny of the impact our operations have on the environment.

The CNSC, an independent regulatory authority established by the federal government under the Nuclear Safety and Control Act (NSCA), is our main federal regulator in Canada. It regulates our compliance with the NSCA and is the federal lead for environmental assessments required to be carried out under the Canadian Environmental Assessment Act, 2012, which was introduced as part of the federal government’s responsible resource development policy.

The primary objectives of an environmental assessment are to ensure that:

• |  | potential adverse environmental effects are considered before proceeding with a project

• |  | projects that cause unjustifiable, significant adverse environmental effects are not permitted to proceed

• |  | appropriate measures are implemented, where necessary, to mitigate risk.

The environmental assessment process has taken more than two years to complete. Our plans to expand production or build new mines in Saskatchewan are subject to this process, and we currently have a number of environmental assessments underway. In certain cases, a review panel may be appointed and public hearings held.

Over the past few years, CNSC audits of our operations have focused on the following SHEQ programs:

• |  | radiation protection

• |  | environmental monitoring

• |  | fire protection

• |  | operational quality assurance

• |  | organization and management systems effectiveness

• |  | transportation systems

• |  | geotechnical monitoring

• |  | training

• |  | ventilation systems.

Improving our environmental performance is challenging and we have several initiatives underway:

• |  | dealing with more stringent controls on fugitive uranium emissions from ventilation systems at fuel services facilities

• |  | optimizing performance of our facilities to reduce molybdenum and selenium loadings

• |  | lessening the impacts our facilities have on groundwater.

2013 ANNUAL INFORMATION FORM Page 88

Many of these initiatives have required additional environmental studies near the operations, and we expect that we will have to do more.

It can take a significant amount of time for regulators to make requested changes to a licence or grant a requested approval because the activity may require an environmental assessment or an extensive review of supporting technical data, management programs and procedures. We are improving the quality of our proposals and submissions and have introduced a number of programs to ensure we continue to comply with regulatory requirements, but this has also increased our capital expenditures and our operating costs.

As our SHEQ management system matures, regulators review our programs and recommend ways to improve our SHEQ performance. These recommendations are generally procedural and do not involve large capital costs, although systems applications can be significant and result in higher operating costs.

We believe that regulatory expectations of the CNSC and other federal and provincial regulators will continue to evolve, and lead to changes to both requirements and the regulatory framework. This will likely increase our expenses.

United States

Our ISR operations in the US have to meet federal, state and local regulations governing air emissions, water discharges, handling and disposal of hazardous materials and site reclamation, among other things.

Mining activities have to meet comprehensive environmental regulations from the US Nuclear Regulatory Commission (NRC), Bureau of Land Management, Environmental Protection Agency and state environmental agencies. The process of obtaining mine permits and licences generally takes several years, and involves environmental assessment reports, public hearings and comments. We have the permits and licences for the US operations that we need to meet our 2014 production plans.

After mining is complete, ISR wellfields have to be restored according to regulatory requirements. This generally involves restoring the groundwater to its pre-mining state or equivalent class of use water standard. Restoration of Crow Butte wellfields is regulated by the Nebraska Department of Environmental Quality and the NRC. Restoration of Smith Ranch-Highland wellfields is regulated by the Wyoming Department of Environmental Quality and the NRC. See pages 92 to 93 for the status of wellfield restoration and regulatory approvals.

Kazakhstan

In its resource use contract with the Kazakhstan government, Inkai committed to conducting its operations according to good international mining practices. It complies with the environmental requirements of Kazakhstan legislation and regulations, and, as an industrial company, it must also reduce, control or eliminate various kinds of pollution and protect natural resources. Inkai is required to submit annual reports on pollution levels to the Kazakhstan environmental, tax and statistics authorities. The authorities conduct tests to validate Inkai’s results.

Environmental protection legislation in Kazakhstan has evolved rapidly, especially in recent years. As the subsoil use sector has evolved, there has been a trend towards greater regulation, heightened enforcement and greater liability for non-compliance. The most significant development was the adoption of the Ecological Code, dated January 9, 2007 and in effect as of February 3, 2007. This code replaced the three main laws that had related to environmental protection. Amendments were made to the code in December 2011 that include more stringent environmental protection regulations, particularly relating to the control of greenhouse gas emissions, obtaining environmental permits, state monitoring requirements and other similar matters.

Inkai is required to comply with environmental requirements during all stages of the project, and must develop an environmental impact assessment for examination by a state environmental expert before making any legal, organizational or economic decisions that could have an effect on the environment and public health. Plans to double production at blocks 1 and 2 and to develop block 3 are subject to this environmental impact assessment process. As a result, a preliminary environmental impact assessment was developed and agreed upon with the relevant government authority.

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Under the Ecological Code, Inkai needs an environmental permit to operate. The permit certifies the holder’s right to discharge emissions into the environment, provided that it introduces the “best available technologies” and complies with the technical guidelines in the code. Inkai has a permit for environmental emissions and discharges, valid until December 2016 and an emissions permit for drilling activities, valid until December 2016. It also holds the required permits under the Water Code.

Government authorities and the courts enforce compliance with these permits, and violations can result in the imposition of administrative, civil or criminal penalties, the suspension or stopping of operations, orders to pay compensation, orders to remedy the effects of violations and orders to take preventive steps against possible future violations. In certain situations, the issuing authority may suspend or revoke the permits.

Inkai has environmental insurance, as required by the Ecological Code and the resource use contract. Inkai also has voluntary civil liability insurance for environment protection.

Nuclear waste management and decommissioning

Once we have permanently stopped mining and processing activities, we are required to decommission the operating sites. This includes reclaiming all waste rock and tailings management facilities and the other areas of the site affected by our activities to the satisfaction of regulatory authorities.

Estimating decommissioning and reclamation costs

We develop conceptual decommissioning plans for our operating sites and use them to estimate our decommissioning costs. We also submit them to regulators to determine the amount of financial assurance we must provide to secure our decommissioning obligations. Our plans include reclamation techniques that we believe generate reasonable environmental and radiological performance. Regulators give “conceptual approval” to a decommissioning plan if they believe the concept is reasonable.

We started conducting reviews of our conceptual decommissioning plans for all Canadian sites in 1996. We typically review them every five years, or when we amend or renew an operating licence. We review our cost estimates for both accounting purposes and licence applications. For our US sites, they are reviewed annually. A preliminary decommissioning plan has been established for Inkai. The plan is updated every five years or as significant changes take place, which would affect the decommissioning estimate.

As properties approach or go into decommissioning, regulators review the detailed decommissioning plans. This can result in additional regulatory process, requirements, costs and financial assurances.

At the end of 2013, our estimate of total decommissioning and reclamation costs was $823 million. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $574 million at the end of 2013 (the present value of the $823 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 as letters of credit to regulatory authorities, as required. We had a total of $768 million in letters of credit supporting our reclamation liabilities at the end of 2013. All of our North American operations have letters of credit in place that provide financial assurance in connection with our preliminary plans for decommissioning for the sites.

Please also see note 17 to the 2013 financial statements for our estimate of decommissioning and reclamation costs and related letters of credit.

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Canada

Decommissioning estimates (100% basis) |  |  |
McArthur River |  | $ | 48 million |
Rabbit Lake |  | $ | 203 million |
Key Lake |  | $ | 218 million | (estimate currently under review)
Cigar Lake |  | $ | 49 million |

We renewed our licences for McArthur River, Rabbit Lake and Key Lake in 2013. We also received an operating licence for Cigar Lake. As part of this process, the preliminary decommissioning plans for each facility were updated and submitted to the CNSC staff and all letters of credit are in the process of being updated. We are in discussions with the CNSC about our Key Lake decommissioning estimate. Depending upon the outcome of discussions, our estimate may increase by an immaterial amount.

The reclamation and remediation activities associated with waste rock and tailings from processing Cigar Lake ore and uranium solution are covered in the plans and cost estimates for the facility that will be processing it.

Decommissioning estimates (100% basis) |  |  |
Port Hope |  | $ | 102 million |
Blind River |  | $ | 39 million |
CFM |  | $ | 20 million |

We renewed our licences for Port Hope, Blind River and CFM in 2012. As part of that process, in 2011, the preliminary decommissioning plans for each facility were accepted by the CNSC staff and all three letters of credit were updated in April 2012 after the licence renewals were granted.

Bruce Power

Operating the Bruce Power nuclear units generates three kinds of radioactive waste:

• |  | used nuclear fuel bundles (high-level radioactive waste)

• |  | other material that has come in close contact with the reactors or is reactor equipment such as pressure tubes. This material is less radioactive than used nuclear fuel bundles (intermediate-level radioactive waste)

• |  | material used in operating the station (low-level radioactive waste).

High-level radioactive waste

Used nuclear fuel bundles from the Bruce reactors are temporarily stored in water-filled pools (called wet bays) at the Bruce Power nuclear stations for a cooling-off period of at least 10 years so their radioactivity substantially decreases. The bundles are then transferred to above-ground concrete canisters at a dry storage facility constructed by OPG. The facility is located on the part of the site not leased to BPLP. OPG started transferring the used nuclear bundles to its facility in 2003.

BPLP is responsible for managing any used nuclear fuel bundles stored in the Bruce B wet bays although OPG retains title to all used nuclear fuel bundles stored in the wet bays before May 11, 2001. OPG also assumes:

• |  | title to any used nuclear fuel bundles that are discharged from the Bruce reactors during the term of the lease

• |  | the cost of, and responsibility for, disposing of these nuclear fuel bundles. It also receives a fee, paid as supplemental rent under the lease, for this disposal.

Intermediate and low-level radioactive waste

OPG has also agreed to take title to, store and dispose of all of BPLP’s low and intermediate-level radioactive waste at OPG’s radioactive waste management facility at the Bruce site during the term of the lease. OPG retains title to all low and intermediate-level radioactive waste generated before May 11, 2001.

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Decommissioning

Under the lease and as owner of the Bruce nuclear plants, OPG is responsible for:

• |  | decommissioning the eight units

• |  | funding the decommissioning and meeting any other related requirements imposed by the CNSC

• |  | managing the radioactive waste associated with decommissioning the Bruce nuclear plants.

Historical waste

When Cameco was formed, we assumed ownership and primary responsibility for managing the waste already existing at the time of the reorganization. This historical waste was all in Ontario, at the historical facilities, which include the Port Hope Conversion Facility, Blind River Refinery, Port Granby Waste Management Facility, Welcome Waste Management Facility and the Centre Pier in Port Hope.

In March 2004, we reached an agreement to transfer two historical facilities and their associated liabilities to the Government of Canada: the Welcome Waste Management Facility and the Port Granby Waste Management Facility. We transferred the Welcome Waste Management Facility and the Port Granby Waste Management Facility to Natural Resources Canada on March 31, 2010 and March 29, 2012, respectively.

In March 2012, we entered into a settlement with Canada Eldor Inc., the entity established by the federal government to assume the historical liabilities and obligations of Eldorado Nuclear Limited, regarding liability for historical waste located at the historical facilities. We are now responsible for all liabilities and costs and expenses related to historical waste and the remaining historical facilities owned or leased by us, which are the Port Hope Conversion Facility, the Blind River Refinery and the Centre Pier in Port Hope.

Recycling uranium byproducts

We have an agreement to process certain uranium-bearing byproducts from Blind River and Port Hope at the White Mesa mill in Blanding, Utah. While this arrangement addresses existing inventory and current recycling requirements, we are considering other outlets.

For example, in 2001, we tested recycling the byproducts at our Key Lake mill, and in 2002 submitted a proposal to federal and provincial regulatory authorities for approval to proceed. We received regulatory approval from the Saskatchewan government in 2003, and were advised by the CNSC in 2011 that this project can proceed. The recycled byproduct material was successfully processed at Key Lake in 2013.

United States

After mining has been completed, an ISR wellfield has to be restored according to regulatory requirements. This generally involves restoring the groundwater to its pre-mining state or equivalent class of water standard.

For wellfield restoration to be complete, regulatory approval is required. It is difficult for us to estimate the timing for wellfield restoration due to the uncertainty in timing for receiving final regulatory approval.

Crow Butte

Restoration of Crow Butte wellfields is regulated by the Nebraska Department of Environmental Quality and the NRC. There are five wellfields being restored at Crow Butte. The groundwater at mine unit #1 has been restored to pre-mining quality standards, all wells are plugged and the piping removed.

Our estimated cost of decommissioning the property is $44 million (US). We have provided the State of Nebraska with a $43.2 million (US) letter of credit as security for decommissioning the property and are in the process of receiving regulatory approval to increase the letter of credit to $44.7 million (US), in accordance with the State of Nebraska’s requirements.

Smith Ranch-Highland

Restoration of Smith Ranch-Highland wellfields is regulated by the Wyoming Department of Environmental Quality and NRC. There are five wellfields being restored at Smith Ranch-Highland, and two wellfields (mine units A and B) that have been fully restored.

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The restoration of mine unit B has been approved by the Wyoming Department of Environmental Quality, and we are waiting for approval from the NRC.

Our estimated cost of decommissioning the property is $202 million (US), including North Butte. We have provided the State of Wyoming with $274 million (US) in letters of credit as security for decommissioning the property, and are in the process of receiving regulatory approval to decrease the letters of credit to $233 million (US), in accordance with the State of Wyoming’s requirements.

Kazakhstan

Inkai is subject to decommissioning liabilities, largely defined by the terms of the resource use contract. Inkai has established a separate bank account and made the required contributions to the account as security for decommissioning. Contributions are set as a percentage of gross revenue and are capped at $500,000 (US). Inkai has funded the full amount.

Under the resource use contract, Inkai must submit a plan for decommissioning the mining facility to the government six months before mining activities are complete. Inkai has established a preliminary plan and an estimate of total decommissioning costs of $14 million (US). It updates the plan every five years, or when there is a significant change at the operation that could affect decommissioning estimates.

Groundwater is not actively restored post-mining in Kazakhstan. See page 87 for additional details.

The regulatory environment

This section, and the section Complying with environmental regulations starting on page 88, discuss some of the more significant government controls and regulations that have a material effect on our business. A significant part of our economic value depends on our ability to comply with the extensive and complex laws and regulations that govern our activities. We are not aware of any proposed legislation or changes to existing legislation that could have a material effect on our business.

International treaty on the non-proliferation of nuclear weapons

The Treaty on the Non-Proliferation of Nuclear Weapons (NPT) is an international treaty that was established in 1970. It has three objectives:

• |  | to prevent the spread of nuclear weapons and weapons technology

• |  | to foster the peaceful uses of nuclear energy

• |  | to further the goal of achieving general and complete disarmament.

The NPT establishes a safeguards system under the responsibility of the International Atomic Energy Agency. Almost all countries are signatories to the NPT, including Canada, the US, the United Kingdom and France. We are therefore subject to the NPT and comply with the International Atomic Energy Agency’s requirements.

Industry regulation and permits

Canada

Our Canadian operations have regulatory obligations to both the federal and provincial governments. There are four main regulatory agencies that issue licences and approvals:

• |  | CNSC (federal)

• |  | Fisheries and Oceans Canada (federal)

• |  | Saskatchewan Ministry of Environment

• |  | Ontario Ministry of Environment.

Environment Canada (federal) is also a main regulatory agency, but does not issue licences and approvals.

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Uranium industry regulation

The government of Canada recognizes the special importance of the uranium industry to Canada’s national interest, and regulates the industry through legislation and regulations, and exerts additional control through government policy.

Federal legislation applies to any work or undertaking in Canada for the development, production or use of nuclear energy or for the mining, production, refinement, conversion, enrichment, processing, reprocessing, possession or use of a nuclear substance. Federal policy requires that any property or plant used for any of these purposes must be legally and beneficially owned by a company incorporated in Canada.

Mine ownership restrictions

The federal government has instituted a policy that restricts ownership of Canadian uranium mining properties to:

• |  | a minimum of 51% ownership by residents

• |  | a basic maximum limit of 49% ownership by non-residents of uranium properties at the first stage of production.

The government may grant exceptions. For example, resident ownership may be less than 51% if the property is Canadian-controlled. Exceptions will only be granted in cases where it is demonstrated that Canadian partners cannot be found, and it must receive Cabinet approval.

The government issued a letter to the Canadian uranium industry on December 23, 1987, outlining the details of this ownership policy. On March 3, 2010, the government announced its intention to liberalize the foreign investment restrictions on Canada’s uranium mining sector to “ensure that unnecessary regulation does not inhibit the growth of Canada’s uranium mining industry by unduly restricting foreign investment”. After striking an expert panel to study the issue and soliciting feedback from various stakeholders, the federal government stated in October 2011 that it would not be changing the policy.

In 2013, it was announced that the proposed Canada-EU Trade Agreement (CETA) contemplates that the Canadian uranium mine ownership requirement would be waived for all European companies. However, at this time CETA has not yet been ratified and remains an agreement in principle and this waiver will not come into effect until such time as CETA is ratified and implemented.

Cameco ownership restriction

We are subject to ownership restrictions under the Eldorado Nuclear Limited Reorganization and Divestiture Act, which restricts the issue, transfer and ownership, including joint ownership, of Cameco shares to prevent both residents and non-residents of Canada from owning or controlling more than a certain percentage of shares. See pages 124 and 125 for more information.

Industry governance

The Nuclear Safety and Control Act (NSCA) is the primary federal legislation governing the control of the mining, extraction, processing, use and export of uranium in Canada. It authorizes the CNSC to make regulations governing all aspects of the development and application of nuclear energy, including uranium mining, milling, conversion, fuel fabrication and transportation. It grants the CNSC licensing authority. A person may only possess or dispose of nuclear substances and build, operate and decommission its nuclear facilities according to the terms and conditions of a CNSC licence. Licensees must satisfy specific conditions of the licence in order to maintain the right to operate their nuclear facilities.

The NSCA emphasizes the importance of environmental as well as health and safety matters, and requires licence applicants and licensees to have adequate provisions for protection.

Regulations made under the NSCA include those dealing with the specific licence requirements of facilities, radiation protection, physical security for all nuclear facilities and the transport of radioactive materials. The CNSC has also issued regulatory documents to assist licensees in complying with regulatory requirements, such as decommissioning, emergency planning, and optimizing radiation protection measures.

All of our Canadian operations are governed primarily by licences granted by the CNSC and are subject to all federal statutes and regulations that apply to us, and all the laws that generally apply in the province where the operation is located, unless there is a conflict with the terms and conditions of the licence or the federal laws that apply to us.

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Uranium export

We must secure export licences and export permits from the CNSC and the Department of Foreign Affairs and International Trade in order to export our uranium. These arrangements are governed by the bi-lateral and multi-lateral agreements that are in place between governments.

Land tenure

Most of our uranium reserves and resources are located in the province of Saskatchewan:

• |  | a mineral claim from the province gives us the right to explore for minerals (other government approvals are required to carry out surface exploration)

• |  | a crown lease with the province gives us the right to mine the minerals on the property

• |  | a surface lease with the province gives us the right to use the land for surface facilities and mine shafts while mining and reclaiming the land.

A mineral claim has a term of two years, with the right to renew for successive one-year periods. Generally, the holder has to spend a certain amount on exploration to keep the mineral claim in good standing. If we spend more than the amount required, the extra amount can be applied to future years.

A holder of a mineral claim in good standing has the right to convert it into a crown lease. A crown lease is for 10 years, with a right to renew for additional 10-year terms. The lessee must spend a certain amount on work during each year of the crown lease. The lease cannot be terminated unless the lessee defaults on any terms of the lease, or under any provisions of The Crown Minerals Act (Saskatchewan) or regulations under it, including any prescribed environmental concerns. Crown leases can be amended unilaterally by the lessor by an amendment to The Crown Minerals Act (Saskatchewan) or The Mineral Disposition Regulations, 1986 (Saskatchewan).

A surface lease can be for up to 33 years, as necessary for operating the mine and reclaiming the land. The province also uses surface leases to specify other requirements relating to environmental and radiation protection as well as socioeconomic objectives.

Electricity regulation

BPLP’s operations are heavily regulated. The CNSC regulates the Bruce nuclear generation stations through its powers under the NSCA (see Uranium industry regulation above). It also monitors the safety performance of the Bruce nuclear generating stations.

Licences issued by the CNSC stipulate that BPLP must report regularly on its operations. BPLP is also regulated by the Nuclear Liability Act (as discussed below), as well as other general legislation.

Licence renewals

BPLP operates the Bruce B nuclear reactors under a CNSC licence issued to BPLP’s general partner, Bruce Power Inc. In 2009, the CNSC renewed the Bruce B operating licence for a term through October 31, 2014. BPLP was not required to provide financial assurances under the Bruce B operating licence because the CNSC determined that the preliminary decommissioning plan and the financial assurances which BPLP provides to OPG under its lease with OPG are adequate.

We are indemnified by BALP for any calls on the assurances resulting from operation of the Bruce A units.

Liability insurance

The Nuclear Liability Act requires operators of nuclear generating facilities to purchase specific amounts of nuclear liability insurance from an approved insurer. The Nuclear Liability Act imposes liability and currently requires the operator of nuclear stations to maintain $75 million of liability insurance for each of its nuclear stations.

The Nuclear Liability Act has two key parts:

• |  | Under Part I, an operator is strictly liable for any damage to public property or personal injury arising from a nuclear incident (as defined in the Nuclear Liability Act), other than damage resulting from sabotage or acts of war. If the Governor in Council is of the opinion that an operator’s liability for a nuclear incident could be higher than $75 million, or it would be in the public interest to provide special measures for compensation, the Governor in Council may proclaim Part II in effect.

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• |  | Under Part II, an operator is liable to the government of Canada for amounts up to $75 million. The Governor in Council may authorize the federal government to pay funds for claims exceeding that amount.

In January 2014, Parliament reintroduced the proposed Nuclear Liability and Compensation Act under Bill C-22, to replace the Nuclear Liability Act. The Nuclear Liability and Compensation Act, as currently proposed, would increase the maximum compensation payable by nuclear operators for a nuclear incident from $75 million to $1 billion (phased in over a three-year period) and modernize Canada’s legislation regarding nuclear liability bringing it in line with international standards. Under the proposed regime, nuclear operators will be required to maintain insurance or alternate financial security (capped at 50% of liability limit) for the full amount of the $1 billion liability limit. The ultimate limitation period for bringing compensation claims for bodily injuries would increase under the proposed regime to 30 years from the current 10 years and a 10-year limitation period would be maintained for all other forms of damage.

Ontario

BPLP sells electricity into the wholesale spot market and contract market.

The Ontario regulatory framework has an impact on BPLP’s marketing of electricity, particularly the wholesale market where BPLP sells most of its production. The Ontario government took steps in April 2005 to mitigate the impact of higher electricity prices on the province’s large industrial and commercial customers by regulating the price of electricity produced by OPG’s base load nuclear and hydro assets. This affected approximately 55,000 large industrial and commercial customers who consume more than 250,000 kilowatt hours per year. In December 2004, OPA was established to ensure reliability of supply in the province. Since 2005, OPA has procured more than 20,000 MW of electricity supply capacity and more than half of the capacity is subject to fixed-rate contract prices.

United States

Uranium industry regulation

In the US, uranium recovery is regulated primarily by the NRC according to the Atomic Energy Act of 1954, as amended. Its primary function is to:

• |  | ensure employees, the public and the environment are protected from radioactive materials

• |  | regulate most aspects of the uranium recovery process.

The NRC’s regulations for uranium recovery facilities are codified in Title 10 of the Code of Federal Regulations (10 CFR). It issues Domestic Source Material Licences under 10 CFR, Part 40. The National Environmental Policy Act (NEPA) governs the review of licence applications, which is implemented through 10 CFR, Part 51.

At Smith Ranch-Highland and Crow Butte, safety is regulated by the federal Occupational Safety and Health Administration.

Other governmental agencies are also involved in the regulation of the uranium recovery industry.

The NRC also regulates the export of uranium from the US and the transport of nuclear materials within the US. It does not review or approve specific sales contracts. It also grants export licences to ship uranium outside the US.

Wyoming

The uranium recovery industry is also regulated by the Wyoming Department of Environmental Quality, the Land Quality Division according to the Wyoming Environmental Quality Act (WEQA) and the Land Quality Division Non-Coal Rules and Regulations under the WEQA. According to the state act, the Wyoming Department of Environmental Quality issues a permit to mine. The Land Quality Division administers the permit.

The state also administers a number of Environmental Protection Agency (EPA) programs under the Clean Air Act and the Clean Water Act. Some of the programs, like the Underground Injection Control Regulations, are incorporated in the Land Quality Division Non-Coal Rules and Regulations. Wyoming currently requires wellfield decommissioning to the standard of pre-mining use.

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Nebraska

The uranium recovery industry is regulated by the NRC, and the Nebraska Department of Environmental Quality according to the Nebraska Environmental Protection Act. The Nebraska Department of Environmental Quality issues a permit to mine. The state requires wellfield groundwater be restored to the class of use water standard.

Land tenure

Our uranium reserves and resources in the US are held by subsidiaries that are located in Wyoming and Nebraska. The right to mine or develop minerals is acquired either by leases from the owners (private parties or the state) or mining claims located on property owned by the US federal government. Our subsidiaries acquire surface leases that allow them to install wellfields and conduct ISR mining.

Kazakhstan

See Kazakhstan government and legislation starting on page 42.

Royalties and taxes

Canadian royalties

We pay royalties to the province of Saskatchewan under the terms of Part III of the Crown Mineral Royalty Regulations pursuant to the Crown Minerals Act. Royalties apply to the sale of all uranium extracted from orebodies in the province. The royalty structure was revised in 2013.

Two types of royalties are paid:

• |  | Basic royalty: This royalty is calculated as 5% of gross sales of uranium, less the Saskatchewan resource credit. This credit became 0.75% as of April 1, 2013 and prior to this date was 1% of the gross sales of uranium.

• |  | Profit royalty (formerly tiered royalty): This royalty was revised retroactively to January 1, 2013. Under the new system, a 10% royalty is charged on profit up to and including $22/kg U3O8 ($9.98/lb) and a 15% royalty is charged on profit in excess of $22/kg U3O8. Profit will be determined as revenue less certain operating, exploration, reclamation and capital costs. Under the new system, both exploration and capital costs will be deductible at the discretion of the producer.

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

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

Canadian income taxes

We are subject to federal income tax and provincial taxes in Saskatchewan and Ontario. Current income tax for 2013 was $14 million.

Royalties are fully deductible for income tax purposes. For Ontario tax purposes, we are charged an additional tax (at normal Ontario corporate tax rates) if the royalty deduction exceeds a notional Ontario resource allowance. Our Ontario fuel services operations and BPLP are eligible for a manufacturing and processing tax credit.

CRA Dispute

Since 2008, the Canada Revenue Agency (CRA) has disputed the offshore marketing company structure and related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2008 tax returns. We 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.

Transfer pricing is a complex area of tax law, and it is difficult to predict the outcome of a case like ours as there are only a handful of reported court decisions on transfer pricing in Canada. However, tax authorities generally test two things:

• |  | the governance (structure)

• |  | the price.

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As the majority of our customers are located outside Canada, we established an offshore marketing subsidiary. This subsidiary entered into intercompany purchase and sales agreements as well as uranium supply agreements with third parties. We have arm’s-length transfer price arrangements in place, which expose both parties to the risks and the rewards accruing to them under this portfolio of purchase and sales contracts.

With respect to the contract prices, they are generally comparable to those established in sales contracts between arm’s-length buyers and sellers entered into at that time. We have recorded a cumulative tax provision of $73 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 to 2013.

We are confident that we will be successful in our case; however, for the years 2003 through 2008, CRA issued notices of reassessment for approximately $2.0 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $590 million. The Canadian Income Tax Act includes provisions that require certain companies to pay 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions and tax loss carryovers, we have been required to pay a net amount of $103 million to CRA ($59 million as of December 31, 2013; $44 million in January 2014), which includes the amounts shown in the table below and described subsequently.

YEAR ($ MILLIONS) |  | CASH TAXES |  |  | INTEREST AND INSTALMENT PENALTIES |  |  | TRANSFER PRICING PENALTIES |  |  | TOTAL |
Prior to 2013 |  |  | — |  |  |  | 13 |  |  |  | — |  |  |  | 13 |
2013 |  |  | 1 |  |  |  | 9 |  |  |  | 36 |  |  |  | 46 |
2014 |  |  | 16 |  |  |  | 28 |  |  |  | — |  |  |  | 44 |
Total |  |  | 17 |  |  |  | 50 |  |  |  | 36 |  |  |  | 103 |

• |  | approximately $13 million for interest and instalment penalties paid prior to 2013. These amounts were not reported separately as they were not material in any given year.

• |  | approximately $27 million in January 2013, representing 50% of the amount owed for the amounts reassessed in December 2012 - $20 million of this payment was refunded in the second quarter of 2013 when it was determined by CRA that they had reassessed amounts outside of the allowable review period.

• |  | approximately $36 million in December 2013 that related to a $72 million transfer pricing penalty we were assessed for the 2007 taxation year. This was the first transfer pricing penalty assessed since CRA began to issue reassessments with respect to the transfer pricing dispute.

• |  | approximately $3 million paid in 2013. This amount would have been refundable in the year, but instead was applied as a credit against the amounts reassessed in December 2013 (for which a further payment was made in January 2014).

• |  | approximately $44 million in January 2014, representing 50% of the amount owed as reassessed in December 2013 and related to the 2008 taxation year.

Using the methodology we believe CRA will continue to apply, and including the $2.0 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $5.7 billion in income as taxable in Canada for the years 2003 through 2013, which would result in a related tax expense of approximately $1.6 billion. As well, CRA may continue to apply transfer price penalties to taxation years subsequent to 2007. As a result, we estimate that cash taxes and transfer pricing penalties would be between $1.25 billion and $1.3 billion. In addition, we estimate there would be interest and instalment penalties applied that would be material to Cameco. We would be responsible for remitting 50% of the cash taxes and transfer pricing penalties (between $625 million and $650 million) plus related interest and instalment penalties assessed, which would be material to Cameco.

Under the Canadian federal and provincial tax legislation, the amount required to be remitted each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers; however, we expect it will generally follow the schedule in the table below.

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DECEMBER 31, 2013 ($ MILLIONS) |  | 2003 – 2013 |  |  | 2014 – 2016 |  |  | 2017 – 2023 |  |  | TOTAL |
50% of cash taxes and transfer pricing penalties payable in the period1 |  |  | 37 |  |  |  | 250 – 275 |  |  |  | 325 – 350 |  |  |  | 625 – 650 |

1 | These amounts do not include interest and instalment penalties, which totaled approximately $22 million to December 31, 2013.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to CRA, including the $103 million already paid to date.

The case on the 2003 reassessment is expected to go to trial in 2015. If this timing is adhered to, we expect to have a Tax Court decision in 2015 or 2016.

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

This discussion of our expectations relating to our tax dispute with CRA and future tax reassessments by CRA, including the amounts of future additional taxable income, additional tax expense, cash taxes payable, transfer pricing penalties, and interest and possible instalment penalties thereon and related remittances, and timing of a Tax Court decision, 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 1 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.

Assumptions

• |  | CRA will reassess us for the years 2009 through 2013 using a similar methodology as for the years 2003 through 2008, with the time lag for the reassessments for each year being similar to what has occurred to date

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

• |  | CRA will seek to impose transfer pricing penalties (10% of the income adjustment) in addition to interest charges and instalment penalties

• |  | we will be substantially successful in our dispute with CRA and the cumulative tax provision of $73 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date.

Material risks that could cause actual results to differ materially

• |  | CRA reassesses us for years 2009 through 2013 using a different methodology than for years 2003 through 2008, or we are unable to utilize elective deductions and loss carryovers to the same extent as anticipated, resulting in the required cash payments to CRA pending the outcome of the dispute being higher than expected

• |  | the time lag for the reassessments for each year is different than for those to date

• |  | we are unsuccessful and the outcome of our dispute with CRA results 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 not related to transfer pricing.

US taxes

Our subsidiaries in Wyoming and Nebraska pay severance taxes, property taxes and Ad Valorem taxes in those states. They paid $4 million (US) in taxes in 2013.

Our US subsidiaries are subject to US federal and state income tax. They may also be subject to the Alternative Minimum Tax (AMT) at a rate of 20%. We can carry forward AMT paid in prior years indefinitely, and apply it as credit against future regular income taxes.

Kazakhstan taxes

The resource use contract lists the taxes, duties, fees, royalties and other governmental charges Inkai has to pay.

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On January 1, 2009, a new tax code of the Republic of Kazakhstan went into effect that includes a number of changes to the taxation regime of subsoil users. The most significant changes involve eliminating the stable tax regime, imposing a mineral extraction tax and changing the payment rate for commercial discovery.

Tax stabilization eliminated

In October 2009, at the request of the Kazakhstan Ministry of Energy and Mineral Resources, Inkai signed an amendment to the resource use contract to adopt the new tax code, eliminating the tax stabilization provision. While we do not expect this to have a material impact on Inkai at this time, eliminating the tax stabilization provision could be material in the future. See pages 41 and 42 for more information about the resource use contract.

Corporate income tax rate

Inkai is subject to corporate income tax at a rate of 20%.

Mineral extraction tax

The tax code includes a Tax on Production of Useful Minerals, a mineral extraction tax replacing the previous royalty. The mineral extraction tax must be paid on each type of mineral and certain other substances that are extracted. Starting from January 1, 2011, the rate used to calculate the mineral extraction tax on uranium was 22%. However, at the end of 2012, the Ministry of Finance introduced a retrospective change to the tax code decreasing the rate to 17.5% for 2009 through 2012 and to 18.5% starting in 2013.

Payment for commercial discovery

Under the resource use contract, a one-time commercial discovery bonus of 0.05% of the value of Kazakh-defined recoverable reserves is paid when there is confirmation that Kazakh-defined recoverable reserves are located in a particular licence area. Under the tax code, the rate increased to 0.1%.

Excess profits tax

The tax code has changed the calculation of excess profits tax. Inkai believes it will not have to pay this tax for the foreseeable future.

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Risks that can affect our business

There are risks in every business.

The nature of our business means we face many kinds of risks and hazards – some that relate to the nuclear energy industry in general, and others that apply to specific properties, operations or planned operations. These risks could have a significant impact on our business, earnings, cash flows, financial condition, results of operations or prospects.

The following section describes the risks that are most material to our business. This is not, however, a complete list of the potential risks we face – there may be others we are not aware of, or risks we feel are not material today that could become material in the future. We have comprehensive systems and procedures in place to manage these risks, but there is no assurance that we will be successful in preventing the harm that any of these risks could cause.

In January, we announced the sale of our 31.6% limited partnership interest in BPLP to BPC Generation Infrastructure Trust, one of the limited partners in BPLP. The purchase price is $450 million and the effective date for the sale is December 31, 2013. Under the agreements governing BPLP, the limited partners have rights of first offer upon a sale by us. The closing of the BPLP transaction is subject to completion or waiver of the right of first offer process by the limited partners and the receipt of certain regulatory and third party approvals. Should such waivers and approvals not be obtained, or should the BPLP transaction be unable to close for any reason, this could have a material and adverse effect on our cash flows, financial condition or results of operations. As the BPLP transaction has not yet closed, this AIF includes a description of the risks associated with our ownership interest in BPLP and BPLP’s operations. If we are unable to close the transaction, we will continue to be subject to these risks as described in this AIF.

Please also see the risk discussion in our 2013 MD&A.

Types of risk |  |
Operational |  | 101
Political |  | 109
Regulatory |  | 111
Financial |  | 112
Environmental |  | 118
Legal and other |  | 119
Industry |  | 121

1 – Operational risks

General operating risks and hazards

We are subject to a number of operational risks and hazards, many of which are beyond our control.

These risks and hazards include:

• environmental damage (including hazardous emissions from our refinery and conversion facilities, such as a release of UF6 or a leak of anhydrous hydrogen fluoride used in the UF6 conversion process) • industrial and transportation accidents, which may involve radioactive or other hazardous materials • labour shortages, disputes or strikes • cost increases for labour, contracted or purchased materials, supplies and services |  | • equipment failures • catastrophic accident • fires • blockades or other acts of social or political activism • regulatory constraints and non-compliance with laws and licences • natural phenomena, such as inclement weather conditions, floods and earthquakes

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• shortages of required equipment, materials and supplies (including the availability of acid for Inkai’s operations in Kazakhstan and anhydrous hydrofluoric acid at our conversion facilities) • transportation disruptions • electrical power interruptions |  | • unusual or unexpected geological or hydrological conditions • underground floods • ground movement or cave-ins • tailings pipeline or dam failures • adverse mining conditions • technological failure of mining methods.

There is no assurance that any of the above risks will not result in:

• damage to or destruction of our properties and facilities located on these properties • personal injury or death • environmental damage • delays in, interruptions of, or decrease in production at our mines, our mills, our refining, conversion or fuel manufacturing facilities, our exploration or development activities or transportation of our products |  | • interruptions or decreases in electricity generation from BPLP • costs, expenses or monetary losses • legal liability • adverse government action.

Any of these events could result in one or more of our operations becoming unprofitable, cause us not to receive an adequate return on invested capital, or have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

Insurance coverage

We buy insurance to cover losses or liabilities arising from some of the operating risks and hazards listed above. We believe we have a reasonable amount of coverage for the risks we choose to insure against. There is no assurance, however, that this coverage will be adequate in all circumstances, that it will continue to be available, that premiums will be economically feasible, or that we will maintain this coverage. Like other nuclear energy and mining companies, we do not have insurance coverage for certain environmental losses or liabilities and other risks, either because it is not available, or because it cannot be purchased at a reasonable cost. We may also be required to increase the amount of our insurance coverage due to changes in the regulation of the nuclear industry.

Not having the right insurance coverage or the right amount of coverage, or having to increase the amount of coverage or choosing not to insure against certain risks, could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

Flooding at our Saskatchewan mines

All of our operating mines in Saskatchewan have had water inflows, and our Cigar Lake development project in Saskatchewan has flooded in the past.

McArthur River

The sandstone that overlays the basement rocks of the McArthur River deposit contains large volumes of water at significant pressure. Ground freezing at McArthur River generally prevents water from flowing into the area being mined and reduces, but does not eliminate the risk of water inflows. There are technical challenges with the groundwater and rock properties.

We temporarily suspended production at our McArthur River mine in April 2003 because increased water inflow from an area of collapsed rock in a new development area began to flood portions of the mine. This caused a major setback in the development of new mining zones.

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Cigar Lake

The Cigar Lake deposit has hydro-geological characteristics and technical challenges that are similar to those at McArthur River. We have had three water inflows at Cigar Lake since 2006 (please see pages 55 and 56 for details).

These water inflows have caused:

| • |  | a significant delay in development and production at the property

| • |  | a significant increase in capital costs

| • |  | the need to notify many of our customers of the interruption in planned uranium supply.

Rabbit Lake

We temporarily reduced our underground activities at Rabbit Lake in November 2007, because there was an increase in water flow from a mining area while an equipment upgrade was limiting surface water-handling system capacity. Rabbit Lake resumed normal mining operations in late December 2007, after the source of the water inflow was plugged.

There is no guarantee that there will not be water inflows at McArthur River, Cigar Lake or Rabbit Lake in the future.

A water inflow could have a material and adverse effect on us, including:

• |  | significant delays or interruptions in production or lower production

• |  | significant delays or interruptions in mine development or remediation activities

• |  | loss of mineral reserves

• |  | a material increase in capital or operating costs.

It could also have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects. The degree of impact depends on the magnitude, location and timing of the flood or water inflow. Floods and water inflows are generally not insurable.

Technical challenges at Cigar Lake and McArthur River

The unique nature of the deposits at McArthur River and Cigar Lake pose many technical challenges, including groundwater management, unstable rock properties, radiation protection, mining method uncertainty at Cigar Lake, ore-handling and transport and other mining-related challenges.

The jet boring mining method was developed and adapted specifically for the Cigar Lake deposit. Although we have successfully demonstrated the jet boring mining method in trials, this method has not been proven at full production. Test mining trials have been completed on a limited number of cavities, including one in waste and one in ore in 2013, that may not be representative of the deposit as a whole. As we ramp up production, there may be some technical challenges, which could affect our production plans, including, but not limited to variable or unanticipated ground conditions, ground movement and cave-ins, water inflows and variable dilution, recovery values and mining productivity. Even though enhancements have been made to the design of the jet boring system units, there is a risk that the rampup to the full production rate at Cigar Lake may not be achieved on a sustained and consistent basis.

Additional modifications are required to be completed at the McClean Lake JEB mill in order to process Cigar Lake ore. There is a risk to Cigar Lake’s ramp up schedule if the McClean Lake JEB mill does not begin processing ore from the Cigar Lake mine by the end of the second quarter, 2014. There is also a risk to our plan to achieve the full production rate of 18 million pounds per year by 2018 if AREVA is unable to complete and commission the required mill upgrades on schedule.

The areas being mined at Cigar Lake 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.

If we are unable to resolve any of these technical challenges, it could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

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Tailings management

Our Key Lake and Rabbit Lake mills produce tailings. Managing these tailings is integral to uranium production.

Key Lake

The Key Lake mill deposits tailings from processing McArthur River ore into the Deilmann TMF. In February 2009, we received regulatory approval to deposit the tailings at a higher elevation at that facility. This is forecast to give us licensed capacity until 2018 at current production rates. We also completed prefeasibility work in 2009, to assess our options for additional long-term tailings storage. In December 2013, Cameco filed the environmental impact statement for the Key Lake extension project to support our application for regulatory approval to deposit tailings at a significantly higher elevation in the Deilmann TMF. Once we receive approval, this would provide us with enough tailings capacity to potentially mill a volume equal to all the known mineral reserves from McArthur River and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

Rabbit Lake

The Rabbit Lake in-pit tailings management facility has the capacity to store tailings from milling ore from Rabbit Lake until approximately 2018. We are continuing to evaluate options to expand the existing tailings management facility to support mining of existing reserves at Rabbit Lake, and provide additional tailings capacity to process ore from other potential sources.

If sloughing or other issues prevent us from maintaining the existing tailings management capacity at the Deilmann TMF and Rabbit Lake pit, or if we do not proceed with, are delayed or do not receive regulatory approval for new or expanded tailings facilities, uranium production could be constrained and this could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

Aging facilities

Our Key Lake and Rabbit Lake mills are old and being refurbished. Our Port Hope fuel services facilities are also aging. This exposes us to a number of risks, including the potential for higher maintenance and operating costs, the need for significant capital expenditures to upgrade and refurbish these facilities, the potential for decreases or delays in, or interruption of, uranium and fuel services production, and the potential for environmental damage.

BPLP’s nuclear generating stations are also aging. Testing and inspection programs have identified issues relating to the equipment life cycle, including corrosion of the steam generator tube, thinning of the feeder pipe wall and contact between the pressure tube and calandria tube. While we understand these conditions are a function of design, the equipment has degraded more quickly than anticipated.

No nuclear generating station using CANDU technology has completed a full life cycle yet, so it is possible that BPLP may have to invest a significant amount of capital in repairing or replacing this and other equipment. BPLP may need to increase its preventive maintenance programs and allow more outage time (a period when a nuclear reactor is not operating) than currently planned.

These risks could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations or on BPLP’s contribution to our earnings, cash flows, financial condition or results of operations.

Reliance on development and expansion projects to fuel growth

Our ability to increase our uranium production depends in part on successfully developing new mines and/or expanding existing operations. Cigar Lake and the McArthur River expansion are our major projects for increasing production.

Several factors affect the economics and success of these projects:

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• |  | capital and operating costs

• |  | metallurgical recoveries

• |  | the accuracy of reserve estimates

• |  | government regulations

• |  | availability of appropriate infrastructure, particularly power and water

• |  | future uranium prices

• |  | the accuracy of feasibility studies

• |  | acquiring surface or other land rights

• |  | receiving necessary government permits.

Generally development projects have no operating history that can be used to estimate future cash flows. We have to invest a substantial amount of capital and time to develop a project and achieve commercial production. A change in costs or construction schedule can affect the economics of a project. Actual costs could increase significantly and economic returns could be materially different from our estimates. We could fail to obtain the necessary governmental approvals for construction or operation. In any of these situations, a project might not proceed according to its original timing, or at all.

It is not unusual in the nuclear energy or mining industries for new or expanded operations to experience unexpected problems during start-up or ramp-up, resulting in delays, higher capital expenditures than anticipated and reductions in planned production. Delays, additional costs or reduced production could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

There is no assurance we will be able to complete the development of new mines, or expand existing operations, economically or on a timely basis.

Developing additional reserves to sustain operations

The McArthur River, Rabbit Lake and Inkai mines are currently our main sources of mined uranium concentrates. Without an expansion of the tailings management facility, production at Rabbit Lake is expected to cease in 2018.

As the reserves at these mines are depleted, our mineral reserves will decrease. We may not be able to sustain production if:

• |  | the Cigar Lake deposit is not successfully developed and does not achieve its planned level of production

• |  | the McArthur River expansion is not successful

• |  | the Inkai block 3, Millennium, Yeelirrie and Kintyre deposits are not successfully developed

• |  | the 2012 MOA 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) cannot be implemented

• |  | production from our US ISR sites is not increased

• |  | we do not proceed with, are delayed or do not receive approval for expanding our tailings capacity at Rabbit Lake

• |  | we do not identify, discover or acquire other deposits

• |  | we do not find extensions to existing orebodies, or

• |  | we do not convert resources to reserves at our mines and development projects.

This could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

Although we have successfully replenished reserves in the past through ongoing exploration, development and acquisition programs, there is no assurance that we will be successful in our current or future exploration, development or acquisition efforts. While we believe that Cigar Lake will achieve its planned levels of production there is no assurance it will.

Nuclear operations risks

Major nuclear incident risk

Although the safety record of nuclear reactors has generally been very good, there have been accidents and other unforeseen problems in the former USSR, the United States, Japan and in other countries. The consequences of a major incident can be severe and include loss of life, property damage and environmental damage. Any resulting liability from a major nuclear incident could exceed BPLP’s resources, and its insurance coverage. In addition, an accident or other significant event at a nuclear plant – operated by BPLP or others – could result in increased regulation, less public support for nuclear energy, lower demand for uranium and lower uranium prices. This could have a material and adverse effect on our own earnings, cash flows, financial condition, results of operations or prospects. If the event occurs at a plant operated by BPLP, this could significantly affect BPLP’s contribution to our earnings, cash flows, financial condition or results of operations.

2013 ANNUAL INFORMATION FORM Page 105

Public acceptance of nuclear energy is uncertain

Maintaining the demand for uranium at current levels and achieving any growth in demand in the future will depend on society’s acceptance of nuclear technology as a means of generating electricity.

On March 11, 2011, a significant earthquake struck the northeast coast of Japan, producing a tsunami and causing massive damage and destruction along the Pacific coastline of Japan. This included damage to the Fukushima-Daiichi nuclear power plant, located in the town of Okuma, about 210 kilometres north of Tokyo. The plant suffered a series of power and equipment failures affecting the cooling water systems and released radioactive material into the environment. The incident at the Fukushima-Daiichi nuclear power plant has called into question public confidence in nuclear energy in Japan and elsewhere around the world. This had an immediate and sustained negative impact on uranium prices and the share price of companies involved in the uranium industry.

Prior to the events of March 11, 2011, Japan had 54 nuclear reactors, which represented 12% of global nuclear generating capacity. As of February 26, 2014, Japan had no reactors operating. Before any of the reactors can be restarted, they must demonstrate an ability to meet new safety standards that were developed by Japan’s newly established Nuclear Regulatory Authority (NRA).

Germany has decided to revert to its previous phase-policy, shutting down eight of its reactors and plans to shut down the remaining nine reactors by 2022.

Lack of public acceptance of nuclear technology would have an adverse effect on the demand for nuclear power and potentially increase the regulation of the nuclear power industry. We may be impacted by changes in regulation and public perception of the safety of nuclear power plants, which could adversely affect the construction of new plants, the re-licensing of existing plants, the demand for uranium and the future prospects for nuclear generation. These events could have a material adverse effect on our own earnings, cash flows, financial condition, results of operations or prospects.

Risks, hazards and potential legal liability with nuclear power

Operating nuclear generating stations has inherent risks, including a substantial risk of liability and the potential for operating costs to rise significantly.

Risks and hazards can result from structural problems, technological problems, nuclear fuel supply, equipment failures, maintenance requirements, regulatory and environmental constraints, security requirements and the storage, handling and disposal of radioactive materials, among other things.

BPLP’s risk management strategies include the safety systems that are a part of CANDU technology, but there is no assurance that risk can be minimized or eliminated. An accident at a nuclear installation anywhere in the world, or other issues, could prompt the CNSC to limit the electrical output or the operation of the Bruce nuclear generation stations, or impose significant conditions on its licence. Any type of accident could also have an impact on the future prospects for nuclear generation.

There is no assurance that these risks and hazards will not result in:

• |  | damage to or destruction of BPLP’s nuclear facilities

• |  | personal injury or death

• |  | environmental damage

• |  | delays in, interruption or decrease of electrical generation or halting of electrical generation from BPLP’s facilities

• |  | costs, expenses or monetary losses

• |  | legal liability

• |  | adverse government action.

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Any of these things could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

Impact of unplanned or extended outages on electrical production

We can be affected by planned outages that are significantly longer than scheduled, and unplanned outages that extend over a period of time. Either of these situations could result in less electricity generated than expected, which could significantly affect BPLP’s contribution to our earnings, cash flows, financial condition or results of operations.

Dependence on reliable transmission systems

BPLP’s ability to sell electricity depends on the capacity, reliability and regulation of the Ontario electricity transmission system and other North American electricity transmission systems that are connected to the Ontario grid. Inadequate or unreliable electricity transmission capacity or disruptions in electricity transmission systems could have a material and adverse effect on BPLP’s contribution to our earnings, cash flows, financial condition or results of operations.

Impact of weather and economic conditions on electrical production

BPLP’s earnings are sensitive to variations in the weather. Variations in winter weather affect the demand for electrical heating, while variations in summer weather affect the demand for electrical cooling. Ontario demand in 2013 was down by 0.7% or 1.0 TWh compared to 2012 (demand in 2012 is after adjusting for the impact of the leap year), mainly due to relatively mild weather in the summer and fall in 2013 and the growth in embedded generation which led to a reduction in demand.

Industrial and wholesale demand for electricity in Ontario has decreased because of weak economic conditions in the province and some parts of North America. Wholesale demand has declined significantly since 2004. While wholesale consumption in 2013 has started to exhibit some strength, gaining 3% or 0.4 TWh from 2012, we believe it will take some time for demand to return to prior levels.

Dependence on a single contractor

BPLP depends on OPG and AECL as single source contractors for certain nuclear support services.

Relying on a single contractor creates a security supply risk for BPLP. If either of these suppliers does not provide quality service or timely service, it could have a material and adverse effect on BPLP’s contribution to our earnings, cash flows, financial condition or results of operations.

Labour and employment

People are core to our business. We compete with other nuclear energy and mining companies for talented, quality people, and we may not always be able to fill positions on a timely basis. There is a limited pool of skilled people and competition is intense. We also experience employee turnover because of an aging workforce.

If we cannot attract and train qualified successors for our senior and operating positions, it could reduce the efficiency of our operations and have an adverse effect on our earnings, cash flows, financial condition or results of operations.

We have unionized employees and face the risk of strikes. At December 31, 2013, we had 3,873 employees (including employees of our subsidiaries, but not including BPLP). This includes 866 unionized employees at McArthur River, Key Lake, Port Hope and at CFM’s facilities, who are members of four different locals of the United Steelworkers trade union. BPLP has 4,076 employees, and most of them are unionized.

Collective agreements

• |  | The collective agreement with the bargaining unit employees at the McArthur River and Key Lake operations expired on December 31, 2013. Negotiations are underway.

• |  | BPLP’s collective agreement with The Society of Energy Professionals expires on December 31, 2014.

We cannot predict whether we or BPLP will reach new collective agreements with these and other employees without a work stoppage or work interruptions while negotiations are underway.

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From time to time, the mining or nuclear energy industry experiences a shortage of tradespeople and other skilled or experienced personnel globally, regionally or locally. We have a comprehensive strategy to attract and retain high calibre people, but there is no assurance this strategy will protect us from the effects of a labour shortage.

A lengthy work interruption or labour shortage could have an adverse effect on our earnings, cash flows, financial condition or results of operations.

Joint ventures

We participate in McArthur River, Key Lake, Cigar Lake, Inkai, Millennium, Kintyre, BPLP and GLE through joint ventures with third parties. Some of these joint ventures are unincorporated, some are incorporated (like Inkai and GLE) and some are partnerships or limited partnerships (like BPLP). We have other joint ventures and may enter into more in the future.

There are risks associated with joint ventures, including:

• |  | disagreement with a joint venture partner about how to develop, operate or finance a project

• |  | a joint venture partner not complying with a joint venture agreement

• |  | possible litigation between joint venture partners about joint venture matters

• |  | the inability to exert control over decisions related to a joint venture we do not have a controlling interest in.

Our joint venture partner in Kazakhstan is a state entity, so its actions and priorities could be dictated by government policies instead of commercial considerations.

These risks could result in legal liability, affect our ability to develop or operate a project under a joint venture, or have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

Supplies and contractors

Supplies

We buy reagents and other production inputs and supplies from suppliers around the world. If there is a shortage of any of these supplies, including parts and equipment, or their costs rise significantly, it could limit or interrupt production or increase production costs. It could also have an adverse effect on our ability to carry out operations or have a material and adverse effect on our earnings, cash flows, financial condition or results of operations. We examine our entire supply chain as necessary to identify areas to diversify or add inventory where we may be vulnerable, but there is no assurance that we will be able to mitigate the risk.

Contractors

In some cases we rely on a single contractor to provide us with reagents or other production inputs and supplies. Relying on a single contractor is a security supply risk because we may not receive quality service, timely service, or service that otherwise meets our needs. These risks could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

Uranium exploration is highly speculative

Uranium exploration is highly speculative and involves many risks, and few properties that are explored are ultimately developed into producing mines.

Even if mineralization is discovered, it can take several years in the initial phases of drilling until a production decision is possible, and the economic feasibility of developing an exploration property may change over time. We are required to make a substantial investment to establish proven and probable mineral reserves, to determine the optimal metallurgical process to extract minerals from the ore, to construct mining and processing facilities (in the case of new properties) and to extract and process the ore. We might abandon an exploration project because of poor results or because we feel that we cannot economically mine the mineralization.

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Given these uncertainties, there is no assurance that our exploration activities will be successful and result in new reserves to expand or replace our current mineral reserves.

Infrastructure

Mining, processing, development and exploration can only be successful with adequate infrastructure. Reliable roads, bridges, power sources and water supply are important factors that affect capital and operating costs and the ability to deliver products on a timely basis.

Our activities could be negatively affected if unusual weather, interference from communities, government or others, aging, sabotage or other causes affect the quality or reliability of the infrastructure.

A lack of adequate infrastructure could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

2 – Political risks

Foreign investments and operations

We do business in countries and jurisdictions outside of Canada and the United States, including the developing world. We also invest in companies that also carry out these activities in these countries. Doing business in these countries poses risks because they have different economic, cultural, regulatory and political environments. Future economic and political conditions could also cause the governments of these countries to change their policies on foreign investments, development and ownership of mineral resources, or impose other restrictions, limitations or requirements that we may not foresee today.

Risks related to doing business in a foreign country can include:

• |  | uncertain legal, political and economic environments

• |  | strong governmental control and regulation

• |  | lack of an independent judiciary

• |  | war, terrorism and civil disturbances

• |  | crime, corruption, making improper payments or providing benefits that may violate Canadian or United States law or laws relating to foreign corrupt practices

• |  | unexpected changes in governments and regulatory officials

• |  | uncertainty or disputes as to the authority of regulatory officials

• |  | changes in a country’s laws or policies, including those related to mineral tenure, mining, imports, exports, tax, duties and currency

• |  | cancellation or renegotiation of permits or contracts

• |  | royalty and tax increases or other claims by government entities, including retroactive claims

• |  | expropriation and nationalization

• |  | delays in obtaining the necessary permits or the inability to obtain or maintain them

• |  | currency fluctuations

• |  | high inflation

• |  | joint venture partners falling out of political favour

• |  | restrictions on local operating companies selling their production offshore, and holding US dollars or other foreign currencies in offshore bank accounts

• |  | import and export regulations, including restrictions on the export of uranium

• |  | limitations on the repatriation of earnings

• |  | increased financing costs.

If one or more of these risks occur, it could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

We also risk being at a competitive disadvantage to companies from countries that are not subject to Canadian or United States law or laws relating to foreign corrupt practices.

We enter into joint venture arrangements with local partners from time to time to mitigate political risk. There is no assurance that these joint ventures will mitigate our political risk in a foreign jurisdiction.

We assess the political risk associated with each of our foreign investments and have political risk insurance to mitigate part of the losses that can arise from some of these risks. From time to time, we assess the costs and benefits of maintaining this insurance and may decide not to buy this coverage in the future. There is no assurance that the insurance will be adequate to cover every loss related to our foreign investments, that coverage will continue to be available or that premiums will be economically feasible. These losses could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations if they are not adequately covered by insurance.

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Kazakhstan

Inkai has a contract with the Kazakhstan government and was granted licences to conduct mining and exploration activities there. Its ability to conduct these activities, however, depends on licences being renewed and other government approvals being granted.

To maintain and increase production at Inkai, we need ongoing support, agreement and co-operation from our partner, Kazatomprom, and from the government. Kazakh foreign investment, environmental and mining laws and regulations are complex and still developing, so it can be difficult to predict how they will be applied. Inkai’s best efforts may therefore not always reflect full compliance with the law, and non-compliance can lead to an outcome that is disproportionate to the nature of the breach.

Subsoil law

Amendments to the subsoil law in 2007 allow the government to reopen resource use contracts in certain circumstances, and in 2009, the Kazakhstan government passed a resolution that classified 231 blocks, including all three Inkai blocks, as strategic deposits. These actions may increase the government’s ability to expropriate Inkai’s properties in certain situations. In 2009, at the request of the Kazakhstan government, Inkai amended the resource use contract to adopt a new tax code, even though the government had agreed to tax stabilization provisions in the original contract.

A new subsoil use law went into effect in 2010 that weakens the stabilization guarantee of the prior law. This development reflects increased political risk in Kazakhstan.

Nationalization

Industries like mineral production are regarded as nationally or strategically important, but there is no assurance they will not be expropriated or nationalized. Government policy can change to discourage foreign investment and renationalize mineral production, or the government can implement new limitations, restrictions or requirements.

There is no assurance that our assets in Kazakhstan and other countries will not be nationalized, taken over or confiscated by any authority or body, whether the action is legitimate or not. While there are provisions for compensation and reimbursement of losses to investors under these circumstances, there is no assurance that these provisions would restore the value of our original investment or fully compensate us for the investment loss. This could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

Government regulations

Our operations in Kazakhstan may be affected in varying degrees by government regulations restricting production, price controls, export controls, currency controls, taxes and royalties, expropriation of property, environmental, mining and safety legislation, and annual fees to maintain mineral properties in good standing. There is no assurance that the laws in Kazakhstan protecting foreign investments will not be amended or abolished, or that these existing laws will be enforced or interpreted to provide adequate protection against any or all of the risks described above. There is also no assurance that the resource use contract can be enforced or will provide adequate protection against any or all of the risks described above.

See pages 42 to 44 for a more detailed discussion of the regulatory and political environment in Kazakhstan.

Australia

State governments in Australia have prohibited uranium mining or uranium exploration from time to time, and from 2002 to 2008, uranium mining was banned in Western Australia, where our Kintyre and Yeelirrie projects are located. A prohibition or restriction on uranium exploration or mining in the future that interferes with the development of Kintyre or Yeelirrie could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

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3 – Regulatory risks

Government laws and regulation

Our business activities are subject to extensive and complex laws and regulations.

There are laws and regulations for uranium exploration, development, mining, milling, refining, conversion, fuel manufacturing, transport, exports, imports, taxes and royalties, labour standards, occupational health, waste disposal, protection and remediation of the environment, decommissioning and reclamation, safety, hazardous substances, emergency response, land use, water use and other matters.

Significant financial and management resources are required to comply with these laws and regulations, and this will likely continue as laws and government regulations become more and more strict. We are unable to predict the ultimate cost of compliance or its effect on our business because legal requirements change frequently, are subject to interpretation and may be enforced to varying degrees.

Some of our operations are regulated by government agencies that exercise discretionary powers conferred by statute. If these agencies do not apply their discretionary authority consistently, then we may not be able to predict the ultimate cost of complying with these requirements or their effect on operations.

Existing, new or changing laws, regulations and standards of regulatory enforcement could increase costs, lower, delay or interrupt production or affect decisions about whether to continue with existing operations or development projects. This could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

If we do not comply with the laws and regulations that apply to our business, then regulatory or judicial authorities could take any number of enforcement actions, including:

• |  | corrective measures that require us to increase capital or operating expenditures or install additional equipment

• |  | remedial actions that result in temporary or permanent shut-down or reduction of our operations

• |  | requirements that we compensate communities that suffer loss or damage because of our activities

• |  | civil or criminal fines or penalties.

Legal and political circumstances are different outside North America, which can change the nature of regulatory risks in foreign jurisdictions when compared with regulatory risks associated with operations in North America.

Permitting and licensing

All mining projects and processing facilities around the world require government approvals, licences or permits, and our operations and development projects in Canada, the US, Kazakhstan and Australia are no exception. Depending on the location of the project, this can be a complex and time consuming process involving multiple government agencies.

We have to obtain and maintain many approvals, licences and permits from the appropriate regulatory authorities, but there is no assurance that they will grant or renew them, approve any additional licences or permits for potential changes to our operations in the future or in response to new legislation, or that they will process any of the applications on a timely basis. Stakeholders, like environmental groups, non-government organizations (NGOs) and aboriginal groups claiming rights to traditional lands, can raise legal challenges. A significant delay in obtaining or renewing the necessary approvals, licences or permits, or failure to receive the necessary approvals, licences or permits, could interrupt or prevent the development or operation of our mining and processing facilities, which could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

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Nuclear plant regulation

BPLP’s nuclear electricity business is subject to extensive government regulations covering nuclear operations, nuclear waste management and decommissioning and environmental matters, and the Bruce B operating licence for its nuclear generation facilities can be revoked if BPLP does not comply. The government also can impose additional conditions on the licences, or impose fines or other penalties. Regulations are promulgated under federal and provincial law.

Because studies revealed that emergency shutdown systems might not have sufficient safety margins for low probability events, the CSNC limited the four Bruce B units to 90% of operating power. The CNSC later approved the uprating of the units to 93% of operating power, but there is no assurance that the CNSC will not significantly derate them in the future.

Compliance with these regulations, the imposition of additional conditions, fines or penalties or a derating of the Bruce B units could have a material adverse effect on BPLP’s contribution to our earnings, cash flows, financial condition or results of operations.

Regulation of the Ontario electricity market

The government of Ontario regulates Ontario’s electricity industry, which opened to competition on May 1, 2002 in both the wholesale and retail markets. The government has since announced regulatory changes, and could make additional or fundamental changes to the structure of the electricity market or new market rules based on the experience of the regulatory authorities and market participants.

Any of these factors could have a material and adverse effect on BPLP’s contribution to our earnings, cash flows, financial conditions or results of operations.

4 – Financial risks

Volatility and sensitivity to prices

Since a significant portion of our revenues come from the sale of uranium and conversion services, our earnings and cash flow are closely related to, and sensitive to, fluctuations in the long and short-term market prices of U3O8 and uranium conversion services.

Many factors beyond our control affect these prices, including the following, among others:

• |  | demand for nuclear power

• |  | forward contracts of U3O8 supplies for nuclear power plants

• |  | political and economic conditions in countries producing and buying uranium

• |  | reprocessing of used reactor fuel and the re-enrichment of depleted uranium tails

• |  | sales of excess civilian and military inventories of uranium by governments and industry participants

• |  | levels of uranium production and production costs

• |  | significant interruptions in production or delays in expansion plans or new mines going into production

• |  | investment and hedge fund activity in the uranium market.

We cannot predict the effect that any one or all of these factors will have on the price of U3O8 and uranium conversion services. Prices have fluctuated widely in the last several years, and there have been significant declines in U3O8 prices since 2008.

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The table below shows the range in spot prices over the last five years.

Range of spot uranium prices US$/lb of U3O8

|  | 2009 |  |  | 2010 |  |  | 2011 |  |  | 2012 |  |  | 2013 |
High |  | $ | 51.50 |  |  | $ | 62.25 |  |  | $ | 72.63 |  |  | $ | 52.13 |  |  | $ | 43.88 |
Low |  |  | 42.00 |  |  |  | 40.75 |  |  |  | 49.13 |  |  |  | 41.75 |  |  |  | 34.50 |

Spot UF6 conversion values US$/kg U

High |  | $ | 8.50 |  |  | $ | 13.00 |  |  | $ | 13.00 |  |  | $ | 10.50 |  |  | $ | 10.50 |
Low |  |  | 5.75 |  |  |  | 5.38 |  |  |  | 8.00 |  |  |  | 6.63 |  |  |  | 8.50 |

The next table shows the range in term prices over the last five years.

Range of term uranium prices US$/lb of U3O8

|  | 2009 |  |  | 2010 |  |  | 2011 |  |  | 2012 |  |  | 2013 |
High |  | $ | 69.50 |  |  | $ | 66.00 |  |  | $ | 71.50 |  |  | $ | 61.25 |  |  | $ | 57.00 |
Low |  |  | 61.00 |  |  |  | 59.00 |  |  |  | 62.00 |  |  |  | 56.50 |  |  |  | 50.00 |

Term UF6 conversion values US$/kg U

High |  | $ | 12.25 |  |  | $ | 15.00 |  |  | $ | 16.75 |  |  | $ | 16.75 |  |  | $ | 16.75 |
Low |  |  | 11.00 |  |  |  | 11.00 |  |  |  | 15.25 |  |  |  | 16.75 |  |  |  | 16.00 |

Notes

Spot and term uranium prices are the average of prices published monthly by Ux Consulting and from The Nuexco Exchange Value, published by TradeTech.

Spot and term UF6 conversion values are the average of the North American prices published monthly by Ux Consulting and from The Nuexco Conversion Value, published by TradeTech.

If prices for U3O8 or uranium conversion services fall below our own production costs for a sustained period, continued production or conversion at our sites may cease to be profitable. This would have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

Declines in U3O8 prices could also delay or deter a decision to build or begin commercial production at one or more of our development projects, or adversely affect our ability to finance these development projects. Either of these could have an adverse effect on our future earnings, cash flows, financial condition, results of operations or prospects.

A sustained decline in U3O8 prices may require us to write down our mineral reserves and mineral resources, and any significant write downs may lead to material write downs of our investment in the mining properties affected, and an increase in charges for amortization, reclamation and closures.

In our uranium segment, we use a uranium marketing strategy as a way to reduce volatility in our future earnings and cash flow from exposure to fluctuations in uranium prices. It involves building a portfolio that consists of fixed-price contracts and market-related contracts with terms of 5 to 10 years (on average). This strategy can create opportunity losses because we may not benefit fully if there is a significant increase in U3O8 prices. This strategy also creates currency risk since we receive payment under the majority of our sales contracts in US$. There is no assurance that our contracting strategy will be successful.

Through our uranium segment and NUKEM, we participate in the uranium spot market from time to time, making purchases so we can put material into higher priced contracts. There are, however, risks associated with spot market purchases, including the risk of losses, which could have an adverse effect on our earnings, cash flows, financial condition or results of operations.

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Spot market electricity prices

Electricity prices can be volatile. BPLP’s risk management activities include trading electricity and related contracts to mitigate these risks. There is no assurance, however, that the activities will be successful.

Reserve, resource, production and capital cost estimates

Reserve and resource estimates are not precise

Our mineral reserves and resources are the foundation of our uranium mining operations. They dictate how much uranium concentrate we can produce, and for how many years.

The uranium mineral reserves and resources reported in this AIF are estimates, and are therefore subjective. There is no assurance that the indicated tonnages or grades of uranium will be mined or milled or that we will receive the uranium price we used in estimating these reserves.

While we believe that the mineral reserve and resource estimates included in this AIF are well established and reflect management’s best estimates, reserve and resource estimates, by their nature, are imprecise, do not reflect exact quantities and depend to a certain extent on statistical inferences that may ultimately prove unreliable. The volume and grade of reserves we actually recover, and rates of production from our current mineral reserves, may be less than the estimate of the reserves. Fluctuations in the market price of uranium, changing exchange rates and operating and capital costs can make reserves uneconomic to mine in the future and ultimately cause us to reduce our reserves.

Short-term operating factors relating to mineral reserves, like the need for orderly development of orebodies or the processing of different ore grades, can also prompt us to modify reserve estimates or make reserves uneconomic to mine in the future, and can ultimately cause us to reduce our reserves. Reserves also may have to be re-estimated based on actual production experience.

Mineral resources may ultimately be reclassified as proven or probable mineral reserves if they demonstrate profitable recovery. Estimating reserves or resources is always affected by economic and technological factors, which can change over time, and experience in using a particular mining method. There is no assurance that any resource estimate will ultimately be reclassified as proven or probable reserves. If we do not obtain or maintain the necessary permits or government approvals, or there are changes to applicable legislation, it could cause us to reduce our reserves.

Mineral resource and reserve estimates can be uncertain because they are based on data from limited sampling and drilling and not from the entire orebody. As we gain more knowledge and understanding of an orebody, the resource and reserve estimate may change significantly, either positively or negatively.

If our mineral reserve or resource estimates for our uranium properties are inaccurate or are reduced in the future, it could:

• |  | require us to write down the value of an operating property, development project, or an evaluation project

• |  | result in lower uranium concentrate production than previously estimated

• |  | require us to incur increased capital or operating costs, or

• |  | require us to operate mines or facilities unprofitably.

This could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations or prospects.

Production and capital cost estimates may be inaccurate

We prepare estimates of future production and capital costs for particular operations, but there is no assurance we will achieve these estimates. Estimates of expected future production and capital costs are inherently uncertain, particularly beyond one year, and could change materially over time.

Production and capital cost estimates for:

• |  | McArthur River assume the successful transition to new mining areas and infrastructure expansion

• |  | Cigar Lake assume that development, mining and production plans proceed as expected

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Production estimates for uranium refining, conversion and fuel manufacturing assume there is no disruption or reduction in supply from us or third party sources, and that estimated rates and costs of processing are accurate, among other things.

Our actual production and capital costs may vary from estimates for a variety of reasons, including, among others:

• |  | actual ore mined varying from estimated grade, tonnage, dilution, metallurgical and other characteristics

• |  | mining and milling losses greater than planned

• |  | short-term operating factors relating to the ore, such as the need for sequential development of orebodies and the processing of new or different ore grades

• |  | risk and hazards associated with mining, milling, uranium refining, conversion and fuel manufacturing

• |  | failure of mining methods and plans

• |  | failure to obtain and maintain the necessary regulatory and partner approvals

• |  | lack of tailings capacity

• |  | natural phenomena, such as inclement weather conditions or floods

• |  | labour shortages or strikes

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

• |  | development, mining or production plans for Cigar Lake are delayed or do not succeed for any reason, including technical difficulties with the jet boring mining method or freezing the deposit to meet production targets, or our inability to solve technical challenges as they arise or acquire any of the required jet boring equipment, or the plan to mill Cigar Lake ore at the McClean Lake JEB mill is delayed or does not succeed for any reason, including technical difficulties with mill modifications or commissioning or milling Cigar Lake ore

• |  | delays, interruption or reduction in production or construction activities due to fires, failure or unavailability of critical equipment, shortage of supplies, underground floods, earthquakes, tailings dam failures, lack of tailings capacity, ground movements and cave-ins, or other difficulties.

Failure to achieve production or capital cost estimates could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

Currency fluctuations

Our earnings and cash flow may also be affected by fluctuations in the exchange rate between the Canadian and US dollar. Our sales of uranium and conversion services are mostly denominated in US dollars, while the production costs of both are denominated primarily in Canadian dollars. Our consolidated financial statements are expressed in Canadian dollars.

Any fluctuations in the exchange rate between the US dollar and Canadian dollar can result in favourable and unfavourable foreign currency exposure, which can have a material effect on our future earnings, cash flows, financial condition or results of operations, as has been the case in the past. While we use a hedging program to limit any adverse effects of fluctuations in foreign exchange rates, there is no assurance that these hedges will eliminate the potential material negative impact of fluctuating rates.

Customers

Our main business relates to the production and sale of uranium concentrates (our uranium segment) and providing uranium conversion services (our fuel services segment). We rely heavily on a small number of customers to purchase a significant portion of our uranium concentrates and conversion services.

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From 2014 through 2016, we expect:

• |  | in our uranium segment, our five largest customers to account for 46% of our contracted supply of U3O8

• |  | in our fuel services segment, our five largest UF6 conversion customers to account for 51% of our contracted supply of UF6 conversion services.

We are a supplier of UO2 used by Canadian CANDU heavy water reactors. Our sales to our largest customer accounted for 44% of our UO2 sales in 2013.

In addition, revenues in 2013 from one customer of our uranium and conversion segments represented $198 million (11%) of our total revenues from those businesses. Sales for the Bruce A and B reactors represent a substantial portion of our fuel manufacturing business.

If we lose any of our largest customers or if any of them curtails their purchases, it could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

Counterparty and credit risk

Our business operations expose us to the risk of counterparties not meeting their contractual obligations, including:

• |  | customers

• |  | suppliers

• |  | financial institutions and other counterparties to our derivative financial instruments and hedging arrangements relating to foreign currency exchange rates and interest rates

• |  | financial institutions which hold our cash on deposit

• |  | insurance providers.

Credit risk is the risk that counterparties will not be able to pay for services provided under the terms of the contract. If a counterparty to any of our significant contracts defaults on a payment or other obligation or becomes insolvent, it could have a material and adverse effect on our cash flows, earnings, financial condition or results of operations.

Uranium products, conversion and fuel services

In our uranium and fuel services segments, we manage the credit risk of our customers for uranium products, conversion and fuel services by:

• |  | monitoring their creditworthiness

• |  | asking for pre-payment or another form of security if they pose an unacceptable level of credit risk.

As of December 31, 2013, 92% of our forecast revenue under contract for the period 2014 to 2016 is with customers whose creditworthiness meets our standards for unsecured payment terms.

Electricity

Excluding revenue support payments from the Ontario government, BPLP’s revenues come from two main sources:

• |  | electricity sales through the spot market administered by government regulators

• |  | electricity sales under short-term, medium-term and long-term power purchase and electricity price hedging agreements.

Spot market participants must meet standards for creditworthiness that are mandated by regulators, so we believe BPLP’s credit risk for sales to these customers is effectively managed. If these purchasers do not provide adequate credit support to the regulators, all market participants, including BPLP, could be responsible for any shortfall, in proportion to their market activity.

BPLP requires purchasers under these agreements to meet certain standards for creditworthiness to manage credit risk. In some cases, they must provide financial assurances as security for non-performance.

Other

We manage the credit risk on our derivative and hedging arrangements, cash deposits and insurance policies by dealing with financial institutions and insurers that meet our credit rating standards and by limiting our exposure to individual counterparties.

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We diversify or increase inventory in our supply chain to limit our reliance on a single contractor, or limited number of contractors. We also monitor the creditworthiness of our suppliers to manage the risk of suppliers defaulting on delivery commitments.

There is no assurance, however, that we will be successful in our efforts to manage the risk of default or credit risk.

Liquidity and financing

Nuclear energy and mining are extremely capital intensive businesses, and companies need significant ongoing capital to maintain and improve existing operations, invest in large scale capital projects with long lead times, and manage uncertain development and permitting timelines and the volatility associated with fluctuating uranium and input prices.

We believe our current financial resources are sufficient to support the exploration and development projects we have planned for 2014. If we expand these projects or our programs overall, we may need to raise additional financing through joint ventures, debt financing, equity financing or other means.

There is no assurance that we will obtain the financing we need, when we need it. Volatile uranium markets, a claim against us, a significant event disrupting our business or operations, or other factors may make it difficult or impossible for us to obtain debt or equity financing on favourable terms, or at all.

Operating and capital plans

We establish our operating and capital plans based on the information we have at the time, including expert opinions. There is no assurance, however, that these plans will not change as new information becomes available or there is a change in expert opinion.

Pre-feasibility and feasibility studies contain estimated capital and operating costs, production and economic returns and other estimates that may be significantly different than actual results, and there is no assurance that they will not be different than anticipated or than what was disclosed in the studies. Our estimates may also be different from those of other companies, so they should not be used to project operating profit.

Internal controls

We use internal controls over financial reporting to provide reasonable assurance that we authorize transactions, safeguard assets against improper or unauthorized use, and record and report transactions properly. This gives us reasonable assurance that our financial reporting is reliable, and prepared in accordance with IFRS.

It is impossible for any system to provide absolute assurance or guarantee reliability, regardless of how well it is designed or operated. We continue to evaluate our internal controls to identify areas for improvement and provide as much assurance as reasonably possible. We conduct an annual assessment of our internal controls over financial reporting and produce an attestation report of their effectiveness by our independent auditors to meet the requirement of Section 404 of the Sarbanes-Oxley Act of 2002.

If we do not satisfy the requirements for internal controls on an ongoing, timely basis, it could negatively affect investor confidence in our financial reporting, which could have an impact on our business and the trading price of our common shares. If a deficiency is identified and we do not introduce new or better controls, or have difficulty implementing them, it could harm our financial results or our ability to meet reporting obligations.

Carrying values of assets

We evaluate the carrying value of our assets to decide whether current events and circumstances indicate whether or not we can recover the carrying amount. This involves comparing the estimated fair value of our reporting units to their carrying values.

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We base our fair value estimates on various assumptions, however, the actual fair values can be significantly different than the estimates. If we do not have any mitigating valuation factors or experience a decline in the fair value of our reporting units, it could ultimately result in an impairment charge.

5 – Environmental risks

Complex legislation and environmental, health and safety risk

Our activities have an impact on the environment, so our operations are subject to extensive and complex laws and regulations relating to the protection of the environment, employee health and safety and waste management. We also face risks that are unique to uranium mining, processing and fuel manufacturing. Laws to protect the environment as well as employee health and safety are becoming more stringent for members of the nuclear energy industry.

Our facilities operate under various operating and environmental approvals, licences and permits that have conditions that we must meet as part of our regular business activities. In a number of instances, our right to continue operating these facilities depends on our compliance with these conditions.

Our ability to obtain approvals, licences and permits, maintain them, and successfully develop and operate our facilities may be adversely affected by the real or perceived impact of our activities on the environment and human health and safety at our development projects and operations and in the surrounding communities. The real or perceived impact of activities of other nuclear energy or mining companies can also have an adverse effect on our ability to secure and maintain approvals, licences and permits.

Our compliance with laws and regulations relating to the protection of the environment, employee health and safety, and waste management requires significant expenditures and can cause delays in production or project development. This has been the case in the past and may be so in the future. Failing to comply can lead to fines and penalties, temporary or permanent suspension of development and operational activities, clean-up costs, damages and the loss of, or the inability to obtain, key approvals, permits and licences. We are exposed to these potential liabilities for our current development projects and operations as well as operations that have been closed. There is no assurance that we have been or will be in full compliance with all of these laws and regulations, or with all the necessary approvals, permits and licences.

Laws and regulations on the environment, employee health and safety, and waste management continue to evolve and this can create significant uncertainty around the environmental, employee health and safety, and waste management costs we incur. If new legislation and regulations are introduced in the future, they could lead to additional capital and operating costs, restrictions and delays at existing operations or development projects, and the extent of any of these possible changes cannot be predicted in a meaningful way.

Environmental and regulatory review is a long and complex process that can delay the opening, modification or expansion of a mine, conversion facility or refining facility, or extend decommissioning activities at a closed mine or other facility.

Our ability to foster and maintain the support of local communities and governments for our development projects and operations is critical to the conduct and growth of our business, and we do this by engaging in dialogue and consulting with them about our activities and the social and economic benefits they will generate. There is no assurance, however, that this support can be fostered or maintained. There is an increasing level of public concern relating to the perceived effect that nuclear energy and mining activities have on the environment and communities affected by the activities. Some NGOs are vocal critics of the nuclear energy and mining industries, and oppose globalization, nuclear energy and resource development. Adverse publicity generated by these NGOs or others, related to the nuclear energy industry or the extractive industry in general, or our operations in particular, could have an adverse effect on our reputation or financial condition and may affect our relationship with the communities we operate in. While we are committed to operating in a socially responsible way, there is no guarantee that our efforts will mitigate this potential risk.

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These risks could delay or interrupt our operations or project development activities, delay, interrupt or lower our production and have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

Decommissioning and reclamation obligations

Environmental regulators are demanding more and more financial assurances so that the parties involved, and not the government, bear the cost of decommissioning and reclaiming sites.

We have filed conceptual decommissioning plans for some of our properties with the regulators. We review these plans for Canadian facilities every five years, or at the time of an amendment or renewal of an operating licence. Plans for our US sites are reviewed every year. Regulators review our conceptual plans on a regular basis. As the sites approach or go into decommissioning, regulators review the detailed decommissioning plans, and this can lead to additional requirements, costs and financial assurances. It is not possible to predict what level of decommissioning and reclamation and financial assurances regulators may require in the future.

If we must comply with additional regulations, or the actual cost of decommissioning and reclamation in the future is significantly higher than our current estimates, this could have a material and adverse effect on our future earnings, cash flows, financial condition or results of operations.

In addition, if a previously unrecognized reclamation liability becomes known or a previously estimated decommissioning or reclamation cost is increased, the amount of that liability or additional cost is expensed, and this can have a material negative effect on our net income for the period.

Nuclear waste management and decommissioning (Bruce Power)

BPLP is subject to extensive federal regulation related to nuclear waste management. Not complying with the regulations could lead to:

• |  | prosecution, and possibly cause the operating licences for its nuclear generation facilities to be revoked

• |  | additional conditions imposed under the licences

• |  | fines and other penalties.

If BPLP releases radioactive material at higher than the prescribed limits, it could lead to a government ordered investigation, control and/or remediation of the release and claims from third parties for harm caused by the release. BPLP already incurs substantial costs for nuclear waste management and changes in federal regulation could result in additional costs that could have a material and adverse effect on BPLP‘s contribution to our earnings, cash flows, financial condition or results of operations.

The wet bays at Bruce B have limited capacity to store used nuclear fuel. Under its contract with BPLP, OPG has started collecting used nuclear fuel bundles, stored in the wet bays, for transport and storage at the OPG dry storage facility at the Bruce site. OPG has title to all used nuclear fuel bundles in the wet bays. If OPG fails to continue providing adequate service to collect the used fuel bundles, does not do it on a timely basis, or experiences problems associated with the station modifications in the wet bays to support the loading of bundles into dry storage containers, this could have a material and adverse effect on BPLP‘s contribution to our earnings, cash flows, financial condition or results of operations.

6 – Legal and other risks

Litigation

We and BPLP are currently subject to litigation or threats of litigation, and may be involved in disputes with other parties in the future that result in litigation. This litigation may involve joint venture partners, suppliers, governments, regulators, tax authorities or other persons.

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We cannot accurately predict the outcome of any litigation. If a dispute cannot be resolved favourably, it may delay or interrupt our operations or project development activities and have a material and adverse effect on our earnings, cash flows, financial condition or results of operations. See Legal proceedings on page 122 for more information.

We are also subject to tax litigation with Canada Revenue Agency. See Canadian income taxes at pages 97 to 99. Substantial success for Canada Revenue Agency would be material, and other unfavourable outcomes for the years 2003 to 2013 could be material, to our cash flows, financial condition or results of operations.

Legal rights

If a dispute arises at our foreign operations, it may be under the exclusive jurisdiction of foreign courts, or we may not be successful in subjecting foreign persons to the jurisdiction of courts in Canada. We could also be hindered or prevented from enforcing our rights relating to a government entity or instrumentality because of the doctrine of sovereign immunity.

The dispute resolution provision of the resource use contract for Inkai stipulates that any dispute between the parties is to be submitted to international arbitration. There is no assurance, however, that a particular government entity or instrumentality will either comply with the provisions of this or any other agreements, or voluntarily submit a dispute to arbitration. If we are unable to enforce our rights under these agreements, this could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

Defects in title

We have investigated our rights to explore and exploit all of our material properties, and those rights are in good standing to the best of our knowledge. There is no assurance, however, that these rights will not be revoked or significantly altered to our detriment, or that our rights will not be challenged by third parties, including local governments and by indigenous groups, such as First Nations and Métis in Canada.

Indigenous rights, title claims and consultation

Managing indigenous rights, title claims and consultation is an integral part of our exploration, development and mining activities, and we are committed to managing them effectively. There is no assurance, however, that we will not face material adverse consequences because of the legal and factual uncertainties with these issues.

Saskatchewan

Exploration, development, mining, milling and decommissioning activities at our various properties in Saskatchewan may be affected by claims by the First Nations and Métis, and related consultation issues.

We also face similar issues with our exploration activities in other provinces and countries.

It is generally acknowledged that under historical treaties, First Nation bands in northern Saskatchewan ceded title to most traditional lands in the region in exchange for treaty benefits and reserve lands. First Nations in Saskatchewan, however, generally continue to assert that their treaties are not an accurate record of their agreement with the Canadian government and that they did not cede title to the minerals when they ceded title to their traditional lands. First Nations have launched a lawsuit in Alberta making a similar claim that they did not cede title to the oil and natural gas rights when they ceded title to their traditional lands. There is a risk that the First Nations in Saskatchewan may launch a similar lawsuit.

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Fuel fabrication defects and product liability

We fabricate nuclear fuel bundles, other reactor components and monitoring equipment. These products are complex and may have defects that can be detected at any point in their product life cycle. Flaws in the products could materially and adversely affect our reputation, which could result in a significant cost to us and have a negative effect on our ability to sell our products in the future. We could also incur substantial costs to correct any product errors, which could have an adverse effect on our operating margins. While we introduced a new rigorous process for review and control in 2007, there is no guarantee that we will detect all defects or errors in our products.

It is possible that some customers may demand compensation if we deliver defective products. If there are a significant number of product defects, it could have a significant impact on our operating results.

Agreements with some customers may include specific terms limiting our liability to customers. Even if there are limited liability provisions in place, existing or future laws, or unfavourable judicial decisions may make them ineffective. We have not experienced any material product liability claims to date, however, they could occur in the future because of the nature of nuclear fuel products. A successful product liability claim could result in significant monetary liability and could seriously disrupt our fuel manufacturing business and the company overall.

7 – Industry risks

Alternate sources of energy

Nuclear energy competes with other sources of energy like oil, natural gas, coal and hydro-electricity. These sources are somewhat interchangeable with nuclear energy, particularly over the longer term.

If lower prices of oil, natural gas, coal and hydro-electricity are sustained over time, it may result in lower demand for uranium concentrates and uranium conversion services, which could lead to lower uranium prices. Growth of the uranium and nuclear power industry will depend on continuing and growing acceptance of nuclear technology to generate electricity. Unique political, technological and environmental factors affect the nuclear industry, exposing it to the risk of public opinion, which could have a negative effect on the demand for nuclear power and increase the regulation of the nuclear power industry. An accident at a nuclear reactor anywhere in the world could affect the acceptance of nuclear energy and the future prospects for nuclear generation, which could have a material and adverse effect on our future earnings, cash flows, financial condition, results of operations or prospects.

Industry competition and international trade restrictions

The international uranium industry, which includes supplying uranium concentrates and providing uranium conversion services, is highly competitive. We market uranium to utilities, and directly compete with a relatively small number of uranium mining and enrichment companies in the world. Their supply may come from mining uranium, excess inventories, including inventories made available from decommissioning of nuclear weapons, reprocessed uranium and plutonium derived from used reactor fuel, and from using excess enrichment capacity to re-enrich depleted uranium tails.

The supply of uranium is affected by a number of international trade agreements and policies. These and any similar future agreements, governmental policies or trade restrictions are beyond our control and may affect the supply of uranium available in the US, Europe and Asia, the world’s largest markets for uranium. If we cannot supply uranium to these important markets, it could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

For conversion services, we compete with three other primary commercial suppliers. In addition, we compete with the availability of additional supplies from excess inventories, including those from decommissioning nuclear weapons and using excess enrichment capacity to re-enrich depleted uranium tails.

Any political decisions about the uranium market can affect our future prospects. There is no assurance that the US or other governments will not enact legislation or take other actions that restricts who can buy or supply uranium, or facilitates a new supply of uranium.

Competition for sources of uranium

There is growing competition for mineral acquisition opportunities throughout the world, so we may not be able to acquire rights to explore additional attractive uranium mining properties on terms that we consider acceptable.

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There is no assurance that we will acquire any interest in additional uranium properties, or buy additional uranium concentrates from the decommissioning of nuclear weapons or the release of excess government inventory, that will result in additional uranium concentrates we can sell. If we are not able to acquire these interests or rights, it could have a material and adverse effect on our future earnings, cash flows, financial condition or results of operations. Even if we do acquire these interests or rights, the resulting business arrangements may ultimately prove not to be beneficial.

Deregulation of the electrical utility industry

A significant part of our future prospects is directly linked to developments in the global electrical utility industry.

Deregulation of the utility industry, especially in the US and Europe, is expected to affect the market for nuclear and other fuels and could lead to the premature shutdown of some nuclear reactors.

Deregulation has resulted in utilities improving the performance of their reactors to record capacity, but there is no assurance this trend will continue.

Deregulation can have a material and adverse effect on our future earnings, cash flows, financial condition or results of operations.

Legal proceedings

We discuss any legal proceedings that we or our subsidiaries are a party to in note 22 to the 2013 financial statements.

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Investor information

Share capital

Our authorized share capital consists of:

• |  | first preferred shares

• |  | second preferred shares

• |  | common shares

• |  | one class B share.

Preferred shares

We do not currently have any preferred shares outstanding, but we can issue an unlimited number of first preferred or second preferred shares with no nominal or par value, in one or more series. The board must approve the number of shares, and the designation, rights, privileges, restrictions and conditions attached to each series of first or second preferred shares.

Preferred shares can carry voting rights, and they rank ahead of common shares and the class B share for receiving dividends and distributing assets if the company is liquidated, dissolved or wound up.

First preferred shares

Each series of first preferred shares ranks equally with the shares of other series of first preferred shares. First preferred shares rank ahead of second preferred shares, common shares and the class B share.

Second preferred shares

Each series of second preferred shares ranks equally with the shares of other series of second preferred shares. Second preferred shares rank after first preferred shares and ahead of common shares and the class B share.

Common shares

We can issue an unlimited number of common shares with no nominal or par value. Only holders of common shares have full voting rights in Cameco.

If you hold our common shares, you are entitled to vote on all matters that are to be voted on at any shareholder meeting, other than meetings that are only for holders of another class or series of shares. Each Cameco share you own represents one vote, except where noted below. As a holder of common shares, you are also entitled to receive any dividends that are declared by our board of directors.

Common shares rank after preferred shares with respect to the payment of dividends and the distribution of assets if the company is liquidated, dissolved or wound up, or any other distribution of our assets among our shareholders if we were to wind up our affairs.

Holders of our common shares have no pre-emptive, redemption, purchase or conversion rights for these shares. Except as described under Ownership and voting restrictions, non-residents of Canada who hold common shares have the same rights as shareholders who are residents of Canada.

As at February 6, 2014, we had 395,627,632 common shares outstanding. These were fully paid and non-assessable.

As of February 6, 2014, there were 9,628,635 stock options outstanding to acquire common shares of Cameco under the company’s stock option plan with exercise prices ranging from $15.79 to $54.38.

In 2013, we granted the following stock options:

• |  | March 1, 2013 – 1,840,932 stock options to acquire common shares of Cameco at an exercise price of $22.00.

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Our articles of incorporation have provisions that restrict the issue, transfer and ownership of voting securities of Cameco (see Ownership and voting restrictions below).

Class B shares

The province of Saskatchewan holds our one class B share outstanding. It is fully paid and non-assessable.

The one class B share entitles the province to receive notices of and attend all meetings of shareholders, for any class or series.

The class B shareholder can only vote at a meeting of class B shareholders, and only as a class if there is a proposal to:

• |  | amend Part 1 of Schedule B of the articles, which states that:

| • |  | Cameco’s registered office and head office operations must be in Saskatchewan

| • |  | the vice-chairman of the board, chief executive officer (CEO), president, chief financial officer (CFO) and generally all of the senior officers (vice-presidents and above) must live in Saskatchewan

| • |  | all annual meetings of shareholders must be held in Saskatchewan

• |  | amalgamate, if it would require an amendment to Part 1 of Schedule B of the articles, or

• |  | amend the articles in a way that would change the rights of class B shareholders.

The class B shareholder can request and receive information from us to determine whether or not we are complying with Part 1 of Schedule B of the articles.

The class B shareholder does not have the right to receive any dividends declared by Cameco. The class B share ranks after first and second preferred shares, but equally with common shareholders, with respect to the distribution of assets if the company is liquidated, dissolved or wound up. The class B shareholder has no pre-emptive, redemption, purchase or conversion rights with its class B share, and the share cannot be transferred.

Ownership and voting restrictions

The federal government established ownership restrictions when Cameco was formed so we would remain Canadian controlled. There are restrictions on issuing, transferring and owning Cameco common shares whether you own the shares as a registered shareholder, hold them beneficially or control your investment interest in Cameco directly or indirectly. These are described in the Eldorado Nuclear Limited Reorganization and Divestiture Act (Canada) (ENL Reorganization Act) and our company articles.

The following is a summary of the restrictions listed in our company articles.

Residents

A Canadian resident, either individually or together with associates, cannot hold, beneficially own or control shares or other Cameco securities, directly or indirectly, representing more than 25% of the votes that can be cast to elect directors.

Non-residents

A non-resident of Canada, either individually or together with associates, cannot hold, beneficially own or control shares or other Cameco securities, directly or indirectly, representing more than 15% of the total votes that can be cast to elect directors.

Voting restrictions

All votes cast at the meeting by non-residents, either beneficially or controlled directly or indirectly, will be counted and pro-rated collectively to limit the proportion of votes cast by non-residents to no more than 25% of the total shareholder votes cast at the meeting.

There have been instances in prior years, including 2013, when we have limited the counting of votes by non-residents of Canada at our annual meeting of shareholders to abide by this restriction. This has resulted in non-residents receiving less than one vote per share.

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Enforcement

The company articles allow us to enforce the ownership and voting restrictions by:

• |  | suspending voting rights

• |  | forfeiting dividends and other distributions

• |  | prohibiting the issue and transfer of Cameco shares

• |  | requiring the sale or disposition of Cameco shares

• |  | suspending all other shareholder rights.

To verify compliance with restrictions on ownership and voting of Cameco shares, we require existing shareholders, proposed transferees or other subscribers for voting shares to declare their residency, ownership of Cameco shares and other things relating to the restrictions. Nominees such as banks, trust companies, securities brokers or other financial institutions who hold the shares on behalf of beneficial shareholders need to make the declaration on their behalf.

We cannot issue or register a transfer of any voting shares if it would result in a contravention of the resident or non-resident ownership restrictions.

If we believe there is a contravention of our ownership restrictions based on any shareholder declarations filed with us, or our books and records or those of our registrar and transfer agent or otherwise, we can suspend all shareholder rights for the securities they hold, other than the right to transfer them. We can only do this after giving the shareholder 30 days’ notice, unless he or she has disposed of the holdings and we have been advised of this.

Understanding the terms

Please see our articles for the exact definitions of associate, resident, non-resident, control, and beneficial ownership which are used for the restrictions described above.

Other restrictions

The ENL Reorganization Act imposes some additional restrictions on Cameco. We must maintain our registered office and our head office operations in Saskatchewan. We are also prohibited from:

• |  | creating restricted shares (these are generally defined as a participating share with restrictive voting rights)

• |  | applying for continuance in another jurisdiction

• |  | enacting articles of incorporation or bylaws that have provisions that are inconsistent with the ENL Reorganization Act.

We must maintain our registered office and head office operations in Saskatchewan under the Saskatchewan Mining Development Corporation Reorganization Act. This generally includes all executive, corporate planning, senior management, administrative and general management functions.

Credit ratings

Credit ratings provide an independent, professional assessment of a corporation’s credit risk. They are not a comment on the market price of a security or suitability for an individual investor and are, therefore, not recommendations to buy, hold or sell our securities.

We provide rating agencies DBRS Limited (DBRS) and Standard & Poor’s (S&P) with confidential, in-depth information to support the credit rating process.

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 and liquidity position.

The rating agencies may revise or withdraw these ratings if they believe circumstances warrant. A material downgrade in our credit ratings would likely increase our cost of funding significantly and our ability to access funding and capital through the capital markets could be reduced.

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We have four series of senior unsecured debentures outstanding:

• |  | $300 million of debentures issued on September 16, 2005 that have an interest rate of 4.7% per year and mature September 16, 2015

• |  | $500 million of debentures issued on September 2, 2009 that have an interest rate of 5.67% per year and mature September 2, 2019

• |  | $400 million of debentures issued on November 14, 2012 that have an interest rate of 3.75% per year and mature on November 14, 2022

• |  | $100 million of debentures issued on November 14, 2012 that have an interest rate of 5.09% per year and mature on November 14, 2042.

We have a commercial paper program which is supported by a $1,250,000 unsecured revolving credit facility that matures November 1, 2018. As of December 31, 2013, there was $25 million outstanding under the commercial paper facility.

The table below shows the current DBRS and S&P ratings and the rating trends/outlooks of our commercial paper and senior unsecured debentures:

Rating Agency |  | Rating |  | Rating Trend/Outlook |
Commercial papers |  |  |  |  |  |
DBRS |  | R-1 (low) |  |  | Stable |
S&P |  | A-1 (low) |  |  | Stable |
Senior Unsecured Debentures |  |  |  |  |  |
DBRS |  | A (low) |  |  | Stable |
S&P |  | BBB+ |  |  | Stable |

DBRS uses rating trends to provide guidance regarding the outlook for the rating assigned. The trend is an indication of the likelihood that the rating could change in the future and the direction in which DBRS considers the rating is headed should present tendencies continue, or in some cases, unless challenges are addressed.

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

The rating agencies may revise or withdraw these ratings if they believe circumstances warrant.

Commercial paper

Rating scales for commercial paper are meant to indicate the risk that a borrower will not fulfill its near-term debt obligations in a timely manner.

The table below explains the credit ratings of our commercial paper in more detail:

|  | Rating |  | Ranking
DBRS rates commercial paper by categories ranging from a high of R-1 to a low of D |  | R-1 (low) |  | • lower end of the R-1 category • represents “satisfactory credit quality” • third highest of 10 available credit ratings
S&P rates commercial paper by categories ranging from a high of A-1 (high) to a low of D |  | A-1 (low) |  | • represents “satisfactory capacity to meet its financial commitments on the obligation” • third highest of eight available credit ratings

Senior unsecured debentures

Long-term debt rating scales are meant to indicate the risk that a borrower will not fulfill its full obligations, with respect to interest and principal, in a timely manner.

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The table below explains the credit ratings of our senior unsecured debentures in more detail:

|  | Rating |  | Ranking
DBRS rates senior unsecured debentures by categories ranging from a high of AAA to a low of D |  | A (low) |  | • lower end of the A category • represents “good credit quality” • third highest of 10 available credit ratings • capacity for the payment of financial obligations is substantial, but of lesser credit quality than AA • may be vulnerable to future events, but qualifying negative factors are considered manageable • “stable” trend means the rating is not likely to change in the future
S&P rates senior unsecured debentures by categories ranging from a high of AAA to a low of D |  | BBB+ |  | • higher end of the BBB category • exhibits “adequate protection parameters” • fourth highest of 10 available credit ratings • adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity to meet financial commitment • “stable” outlook means the rating is not likely to change in the future

Payments to Credit Rating Agencies

We paid $756,374 in connection with the credit ratings disclosed above, of that $435,000 related to new issuance fees for the ratings of the senior unsecured debentures issued in 2012.

Material contracts

We are required by law to describe our material contracts in this AIF (not including material contracts that we entered into as part of the ordinary course of business) that we entered into before 2013 and remain in effect – there are five, which are described below. We did not enter into any material contracts in 2013 that remain in effect. We did enter into a material contract in 2014, which is described below.

Supplemental indentures

We entered into the Third supplemental indenture with CIBC Mellon Trust Company (CIBC Mellon) on September 16, 2005, relating to the issue of $300 million in unsecured debentures at an interest rate of 4.7% per year and due in 2015.

We entered into the Fourth supplemental indenture with CIBC Mellon on September 2, 2009, relating to the issue of $500 million in unsecured debentures at an interest rate of 5.67% per year and due in 2019.

We entered into the Fifth supplemental indenture with CIBC Mellon on November 14, 2012, relating to the issue of $400 million in unsecured debentures at an interest rate of 3.75% per year and due in 2022.

We entered into the Sixth supplemental indenture with CIBC Mellon on November 14, 2012, relating to the issue of $100 million in unsecured debentures at an interest rate of 5.09% per year and due in 2042.

See Senior unsecured debentures, above for more information about these debentures.

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US Trust Indenture

We entered into an indenture with The Bank of New York Mellon on May 22, 2012 to set forth the general terms and provisions of debt securities. The terms of this indenture were fully described in our final short form base shelf prospectus dated May 29, 2012. We have not issued any debt securities under this indenture. The specific terms of any offering of debt securities under this indenture would be set forth in a shelf prospectus supplement.

BPLP Sale Agreement

On January 30, 2014, Cameco and our wholly-owned subsidiaries, Cameco Bruce Holdings Inc. and Cameco Bruce Holdings II Inc. entered into a purchase and sale agreement to sell their aggregate 31.6% limited partnership interest in BPLP and 333 1⁄3 common shares in the capital of Bruce Power Inc. (BPI) to BPC Generation Infrastructure Trust, one of the limited partners in BPLP and one of the shareholders in BPI.

The purchase price is $450 million and the effective date for the sale is December 31, 2013. Under the agreements governing BPLP, the limited partners have rights of first offer upon a sale by us. The closing of the BPLP transaction is subject to completion or waiver of the right of first offer process by the limited partners and the receipt of certain regulatory and third party approvals.

Market for our securities

Our common shares are listed and traded on the Toronto Stock Exchange (under the symbol CCO) and the New York Stock Exchange (under the symbol CCJ).

We have a registrar and transfer agent in Canada (CST) and the US (American Stock Transfer) for our common shares:

Canada |  | CST Trust Company P.O. Box 700, Station B Montreal, Quebec H3B 3K3 |  | US |  | American Stock Transfer & Trust Company, LLC 6201 15th Avenue Brooklyn, New York United States of America 11219

Trading activity

The table below shows the high and low closing prices and trading volume for our common shares on the TSX in 2013.

2013 |  | High ($) |  |  | Low ($) |  |  | Volume |
January |  |  | 21.88 |  |  |  | 19.07 |  |  |  | 27,722,874 |
February |  |  | 23.25 |  |  |  | 20.74 |  |  |  | 29,876,478 |
March |  |  | 22.32 |  |  |  | 20.95 |  |  |  | 18,769,535 |
April |  |  | 21.22 |  |  |  | 17.89 |  |  |  | 23,904,823 |
May |  |  | 23.49 |  |  |  | 18.60 |  |  |  | 28,642,516 |
June |  |  | 22.60 |  |  |  | 20.79 |  |  |  | 19,430,760 |
July |  |  | 23.35 |  |  |  | 20.84 |  |  |  | 21,127,684 |
August |  |  | 21.23 |  |  |  | 19.84 |  |  |  | 12,878,225 |
September |  |  | 21.40 |  |  |  | 18.50 |  |  |  | 17,489,546 |
October |  |  | 20.59 |  |  |  | 17.95 |  |  |  | 22,919,300 |
November |  |  | 22.08 |  |  |  | 19.33 |  |  |  | 19,587,568 |
December |  |  | 22.61 |  |  |  | 21.22 |  |  |  | 20,316,112 |

Dividend policy

The board established a policy of paying quarterly dividends when we launched our initial public offering in 1991. It reviews the dividend policy from time to time in light of our financial position and other factors they consider relevant.

The table below shows the dividends per common share for the last three fiscal years.

|  | 2013 |  |  | 2012 |  |  | 2011 |
Cash dividends |  | $ | 0.40 |  |  | $ | 0.40 |  |  | $ | 0.40 |

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Governance

Directors

Director |  | Board committees |  | Principal occupation or employment
Ian Bruce Calgary, Alberta, Canada Director since 2012 |  | Audit and finance Reserves oversight Safety, health and environment |  | Corporate director as of 2010 2010 to 2011 – Co-Chairman, Peters & Co. Limited 2002 to 2010 – Chief Executive Officer, Peters & Co. Limited
Daniel Camus Geneva, Switzerland Director since 2011 |  | Audit and finance Human resources and compensation Safety, health and environment |  | Corporate director as of 2011 2012 to present – Chief Financial Officer of The Global Fund to Fight Aids, Tuberculosis and Malaria 2005 to 2010 – Head of Strategy and International Activities of Electricité de France SA 2002 to 2010 – Group chief financial officer of Electricité de France SA
John Clappison Toronto, Ontario, Canada Director since 2006 |  | Audit and finance (Chair) Nominating, corporate governance and risk |  | Corporate director as of 2006
Joe Colvin Santa Fe, New Mexico, USA Director since 1999 |  | Safety, health and environment (Chair) Human resources and compensation |  | June 2011 to present – Past-President of American Nuclear Society June 2010 to June 2011 – President of American Nuclear Society February 2005 to present – President emeritus of the Nuclear Energy Institute
James Curtiss Wagener, South Carolina, USA Director since 1994 |  | Human resources and compensation (Chair) Nominating, corporate governance and risk |  | April 2008 to present – principal of Curtiss Law
Donald Deranger Prince Albert, Saskatchewan, Canada Director since 2009 |  | Reserves oversight Safety, health and environment |  | May 2013 to present – non-executive chair of the board of Points Athabasca Contracting LP 1997 to present – Advisor to the Athabasca Basin Development Corporation 2001 to May 2013 – President of Points Athabasca Contracting LP 2003 to 2012 – Athabasca Vice Chief of the Prince Albert Grand Council
Catherine Gignac Mississauga, Ontario, Canada Director since 2014 |  | None |  | September 2011 to present – principal of Catherine Gignac & Associates April 2009 to September 2011 – mining equity research analyst with NCP Northland Capital Partners February 2005 to February 2009 – mining equity research analyst with Wellington West Capital Markets
Tim Gitzel Saskatoon, Saskatchewan, Canada Director since 2011 |  | None |  | July 2011 to present – President and CEO May 2010 to June 2011 – President January 2007 to May 2010 – Senior Vice-President and Chief Operating Officer

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Director |  | Board committees |  | Principal occupation or employment
James Gowans Toronto, Ontario, Canada Director since 2009 |  | Reserves oversight (Chair) Safety, health and environment |  | January 2014 to present – Executive Vice-President and Chief Operating Officer of Barrick Gold Corporation January 2011 to January 2014 – Managing Director, Debswana Diamond Company March 2010 to December 2010 – COO and Chief Technical Officer of DeBeers SA
Nancy Hopkins Saskatoon, Saskatchewan, Canada Director since 1992 |  | Nominating, corporate governance and risk (Chair) Audit and finance |  | 1984 to present – Lawyer, partner, McDougall Gauley LLP
Anne McLellan Edmonton, Alberta, Canada Director since 2006 |  | Audit and finance Nominating, corporate governance and risk Human resources and compensation |  | July 2006 to present – Senior Advisor at Bennett Jones LLP July 2006 to June 2013 – Distinguished Scholar in Residence at Alberta Institute for American Studies, University of Alberta
Neil McMillan Saskatoon, Saskatchewan, Canada Director since 2002 |  | Chair |  | 2004 to present – President and Chief Executive Officer, Claude Resources Inc.
Victor Zaleschuk Calgary, Alberta, Canada Director since 2001 |  | Human resources and compensation Nominating, corporate governance and risk Reserves oversight |  | 2001 to present – Corporate director

All of the directors are elected for a term of one year, and hold office until the next annual meeting unless he or she steps down, as required by corporate law.

Officers

Officer |  | Principal occupation or employment for past five years
Neil McMillan Chair of the Board Saskatoon, Saskatchewan, Canada |  | 2004 to present – President and Chief Executive Officer, Claude Resources Inc.
Tim Gitzel President and Chief Executive Officer Saskatoon, Saskatchewan, Canada |  | Assumed current position July 2011 May 2010 to June 2011 – President January 2007 to May 2010 – Senior Vice-President and Chief Operating Officer
Gary Chad Senior Vice-President, Chief Legal Officer and Corporate Secretary Saskatoon, Saskatchewan, Canada |  | Assumed current position January 2000
Grant Isaac Senior Vice-President and Chief Financial Officer Saskatoon, Saskatchewan, Canada |  | Assumed current position July 2011 July 2009 to July 2011 – Senior Vice-President, Corporate Services 2006 to 2009 – Dean of Edwards School of Business (formerly College of Commerce), University of Saskatchewan

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Officer |  | Principal occupation or employment for past five years
Ken Seitz Senior Vice-President and Chief Commercial Officer Saskatoon, Saskatchewan, Canada |  | Assumed current position January 2011 2009 to December 2010 – Vice-President, Marketing Strategy and Administration 2006 to 2009 – Vice-President, Corporate Development and Power Generation
Robert Steane Senior Vice-President and Chief Operating Officer Saskatoon, Saskatchewan, Canada |  | Assumed current position May 2010 2007 to May 2010 – Vice-President, Major Projects
Alice Wong Senior Vice-President and Chief Corporate Officer Saskatoon, Saskatchewan, Canada |  | Assumed current position July 2011 October 2008 to July 2011 – Vice-President, Safety, Health, Environment, Quality and Regulatory Relations

To our knowledge, the total number of common shares that the directors and executive officers as a group either: (i) beneficially owned; or (ii) exercised direction or control over, directly or indirectly, was 319,071 as at February 24, 2014. This represents less than 1% of our outstanding common shares.

To the best of our knowledge, none of the directors, executive officers or shareholders that either: (i) beneficially owned; or (ii) exercised direction or control of, directly or indirectly, over 10% of any class of our outstanding securities, nor their associates or affiliates, have or have had within the three most recently completed financial years, any material interests in material transactions which have affected, or will materially affect, the company.

Other information about our directors and officers

None of our directors or officers, or a shareholder with significant holdings that could materially affect control of us, is or was a director or executive officer of another company in the past 10 years that:

• |  | was the subject of a cease trade or similar order, or an order denying that company any exemption under securities legislation, for more than 30 consecutive days while the director or executive officer held that role with the company

• |  | was involved in an event that resulted in the company being subject to one of the above orders after the director or executive officer no longer held that role with the company

• |  | while acting in that capacity, or within a year of acting in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of that company, except for Nancy Hopkins who is currently a director of Growthworks Canadian Fund Ltd. which has obtained court protection under the Companies’ Creditors Arrangement Act.

None of them in the past 10 years:

• |  | became bankrupt

• |  | made a proposal under any legislation relating to bankruptcy or insolvency

• |  | has been subject to or launched any proceedings, arrangement or compromise with any creditors, or

• |  | had a receiver, receiver manager or trustee appointed to hold any of their assets.

None of them has ever been subject to:

• |  | penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, or

• |  | any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

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About the audit and finance committee

Audit and finance committee charter

See appendix A for a copy of the audit and finance committee charter. You can also find a copy on our website (cameco.com/responsibility/governance/board_committees).

Composition of the audit and finance committee

The committee is made up of five members: John Clappison (chair), Ian Bruce, Daniel Camus, Nancy Hopkins and Anne McLellan. Each member is independent and financially literate using criteria that meet the standards of the Canadian Securities Administrators as set out in National Instrument 52-110.

Relevant education and experience

John Clappison, a corporate director, is the former managing partner of the Greater Toronto Area office of PricewaterhouseCoopers LLP (PwC). He is our committee chair and currently serves on the boards of two other publicly traded companies, on one of which he is the chair of their audit committee and one of which he is a member of their audit committee. Mr. Clappison has over 35 years of experience as a practicing chartered accountant and was an audit partner at PwC. He serves on boards of other private and not-for-profit organizations. Mr. Clappison is a chartered accountant and a Fellow of the Institute of Chartered Accountants of Ontario.

Ian Bruce, a corporate director, is the former co-chairman of the board of Peters & Co. Limited, an independent investment dealer. Over the course of his career at Peters & Co. Limited from 1998 to May 2011, Mr. Bruce was vice chairman, president and CEO, CEO and co-chairman. He was a past member of the Expert Panel on Securities Regulation for the Minister of Finance of Canada. Mr. Bruce was a board member and chair of the Investment Industry Association of Canada, and also served as a director of the public companies Hardy Oil & Gas plc from 2008 to 2012 and Taylor Gas Liquids Ltd. from 1997 to 2008. He currently serves on the board of one other publicly traded company and four private companies. Mr. Bruce is a fellow of the Canadian Institute of Chartered Accountants of Alberta, a recognized Specialist in Valuation under Canadian CICA rules, and has his Corporate Finance Specialist designation in Canada and the UK.

Daniel Camus, a corporate director, is the former group chief financial officer and former head of strategy and international activities of Electricité de France SA (EDF), a France-based integrated energy operator active in the generation, distribution, transmission, supply and trading of electrical energy with international subsidiaries. He currently serves on the boards of four other publicly traded companies, on three of which he is the chair of the audit committee. Cameco’s board has approved Mr. Camus sitting on four audit committees of publicly traded companies, including Cameco. He is the Chief Financial Officer of the humanitarian finance organization, The Global Fund to Fight AIDS, Tuberculosis and Malaria. Mr. Camus received his PhD in Economics from Sorbonne University and an MBA in finance and economics from the Institute d’Études Politiques de Paris.

Nancy Hopkins is a partner with the law firm of McDougall Gauley, LLP in Saskatoon where she concentrates her practice on corporate, commercial and tax law. She currently serves on the boards of two other publicly traded companies and the Canadian Pension Plan Investment Board. She formerly served on the boards of the Canadian Institute of Chartered Accountants and the Saskatchewan Airport Authority as well as the board of governors of the University of Saskatchewan. Ms. Hopkins received her bachelor of commerce and law degrees from the University of Saskatchewan, and is an honorary member of the Institute of Chartered Accountants of Saskatchewan.

The Honourable Anne McLellan is a former Deputy Prime Minister of Canada and has held several senior cabinet positions, including federal Minister of Natural Resources, Minister of Health, Minister of Justice and Attorney General of Canada, and federal interlocutor of Métis and non-status Indians. Since leaving politics, she served as distinguished scholar in residence at the University of Alberta in the Alberta Institute for American Studies from 2006-2013 and is a senior advisor in the national law firm Bennett Jones LLP. She currently serves on the board of one other publicly traded company. She also serves as a director on the boards of the Royal Alexandra Hospital Foundation and the Edmonton Regional Airport Authority. Ms. McLellan holds a bachelor of arts degree and a law degree from Dalhousie University, and a master of laws degree from King’s College, University of London.

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Auditors’ fees

The table below shows the fees we paid to the external auditors for services in 2013 and 2012:

|  | 2013 ($) |  |  | % of total fees (%) |  |  | 2012 ($) |  |  | % of total fees (%) |
Audit fees |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cameco |  |  | 1,443,700 |  |  |  | 45.9 |  |  |  | 1,581,700 |  |  |  | 60.4 |
Subsidiaries |  |  | 879,500 |  |  |  | 28.0 |  |  |  | 376,400 |  |  |  | 14.4 |
Total audit fees |  |  | 2,323,200 |  |  |  | 73.9 |  |  |  | 1,958,100 |  |  |  | 74.8 |
Audit-related fees |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Translation services |  |  | 67,200 |  |  |  | 2.1 |  |  |  | 138,600 |  |  |  | 5.3 |
Pensions and other |  |  | 104,300 |  |  |  | 3.3 |  |  |  | 68,300 |  |  |  | 2.6 |
Total audit-related fees |  |  | 171,500 |  |  |  | 5.4 |  |  |  | 206,900 |  |  |  | 7.9 |
Tax fees |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Compliance |  |  | 252,500 |  |  |  | 8.0 |  |  |  | 125,000 |  |  |  | 4.8 |
Planning and advice |  |  | 398,600 |  |  |  | 12.7 |  |  |  | 329,000 |  |  |  | 12.5 |
Total tax fees |  |  | 651,100 |  |  |  | 20.7 |  |  |  | 454,000 |  |  |  | 17.3 |
All other fees |  |  | — |  |  |  | 0.0 |  |  |  | – |  |  |  | 0.0 |
Total fees |  |  | 3,145,800 |  |  |  | 100.0 |  |  |  | 2,619,000 |  |  |  | 100.0 |

Approving services

The audit and finance committee must pre-approve all services the external auditors will provide to make sure they remain independent. This is according to our audit and finance committee charter and consistent with our corporate governance practices. The audit and finance committee pre-approves services up to a specific limit. If we expect the fees to exceed the limit, or the external auditors to provide new audit or non-audit services that have not been pre-approved in the past, then this must be pre-approved separately.

Any service that is not generally pre-approved must be approved by the audit and finance committee before the work is carried out, or by the committee chair, or board chair in his or her absence, as long as the proposed service is presented to the full audit and finance committee at its next meeting.

The committee has adopted a written policy that describes the procedures for implementing these principles.

Interest of experts

Our auditor is KPMG LLP, independent chartered accountants, who have audited our 2013 financial statements.

KPMG LLP is independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Saskatchewan.

The individuals who are qualified persons for the purposes of NI 43-101 and employees of Cameco are listed under Mineral reserves and resources on page 76. As a group, they beneficially own, directly or indirectly, less than 1% of any class of the outstanding securities of Cameco and our associates and affiliates.

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Appendix A

Audit and finance committee of the Board of Directors

Mandate

Purpose

The primary purpose of the audit and finance committee (committee) is to assist the board of directors (board) in fulfilling its oversight responsibilities for (a) the accounting and financial reporting processes, (b) the internal controls, (c) the external auditors, including performance, qualifications, independence, and their audit of the corporation’s financial statements, (d) the performance of the corporation’s internal audit function, (e) financial matters and risk management of financial risks as delegated by the board, (f) the corporation’s process for monitoring compliance with laws and regulations (other than environmental and safety laws) and its code of conduct and ethics, and (g) prevention and detection of fraudulent activities. The committee shall also prepare such reports as required to be prepared by it by applicable securities laws.

In addition, the committee provides an avenue for communication between each of the internal auditor, the external auditors, management, and the board. The committee shall have a clear understanding with the external auditors that they must maintain an open and transparent relationship with the committee and that the ultimate accountability of the external auditors is to the board and the committee, as representatives of the shareholders. The committee, in its capacity as a committee of the board, subject to the requirements of applicable law, is directly responsible for the appointment, compensation, retention, and oversight of the external auditors.

The committee has the authority to communicate directly with the external auditors and internal auditor.

The committee shall make regular reports to the board concerning its activities and in particular shall review with the board any issues that arise with respect to the quality or integrity of the corporation’s financial statements, the performance and independence of the external auditors, the performance of the corporation’s internal audit function, or the corporation’s process for monitoring compliance with laws and regulations other than environmental and safety laws.

Composition

The board shall appoint annually, from among its members, a committee and its chair. The committee shall consist of at least three members and shall not include any director employed by the corporation.

Each committee member will be independent pursuant to the standards for independence adopted by the board.

Each committee member shall be financially literate with at least one member having accounting or related financial expertise, using the terms defined as follows:

“Financially literate” means the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the corporation’s financial statements; and

“Accounting or related financial expertise” means the ability to analyse and interpret a full set of financial statements, including the notes attached thereto, in accordance with Canadian generally accepted accounting principles.

In addition, where possible, at least one member of the committee shall qualify as an “audit committee financial expert” within the meaning of applicable securities law.

Members of the committee may not serve on the audit and finance committees of more than three public companies (including Cameco’s) without the approval of the board.

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Meetings

The committee will meet at least four times annually and as many additional times as the committee deems necessary to carry out its duties effectively. The committee will meet separately in private with the external auditors, the internal auditor and management at each regularly scheduled meeting.

A majority of the members of the committee shall constitute a quorum. No business may be transacted by the committee except at a meeting of its members at which a quorum of the committee is present.

The committee may invite such officers, directors and employees of the corporation as it may see fit from time to time to attend at meetings of the committee and assist thereat in the discussion and consideration of any matter.

A meeting of the committee may be convened by the chair of the committee, a member of the committee, the external auditors, the internal auditor, the chief executive officer or the chief financial officer. The secretary, who shall be appointed by the committee, shall, upon direction of any of the foregoing, arrange a meeting of the committee. The committee shall report to the board in a timely manner with respect to each of its meetings.

Duties and responsibilities

To carry out its oversight responsibilities, the committee shall:

Financial reporting process

1. | Review with management and the external auditors any items of concern, any proposed changes in the selection or application of major accounting policies and the reasons for the change, any identified risks and uncertainties, and any issues requiring management judgement, to the extent that the foregoing may be material to financial reporting.

2. | Consider any matter required to be communicated to the committee by the external auditors under applicable generally accepted auditing standards, applicable law and listing standards, including the external auditors’ report to the committee (and management’s response thereto) on: (a) all critical accounting policies and practices used by the corporation; (b) all material alternative accounting treatments of financial information within generally accepted accounting principles that have been discussed with management, including the ramifications of the use of such alternative treatments and disclosures and the treatment preferred by the external auditors; and (c) any other material written communications between the external auditors and management.

3. | Require the external auditors to present and discuss with the committee their views about the quality, not just the acceptability, of the implementation of generally accepted accounting principles with particular focus on accounting estimates and judgements made by management and their selection of accounting principles.

4. | Discuss with management and the external auditors (a) any accounting adjustments that were noted or proposed (i.e. immaterial or otherwise) by the external auditors but were not reflected in the financial statements, (b) any material correcting adjustments that were identified by the external auditors in accordance with generally accepted accounting principles or applicable law, (c) any communication reflecting a difference of opinion between the audit team and the external auditors’ national office on material auditing or accounting issues raised by the engagement, and (d) any “management” or “internal control” letter issued, or proposed to be issued, by the external auditors to the corporation.

5. | Discuss with management and the external auditors any significant financial reporting issues considered during the fiscal period and the method of resolution. Resolve disagreements between management and the external auditors regarding financial reporting.

6. | Review with management and the external auditors (a) any off-balance sheet financing mechanisms being used by the corporation and their effect on the corporation’s financial statements and (b) the effect of regulatory and accounting initiatives on the corporation’s financial statements, including the potential impact of proposed initiatives.

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7. | Review with management and the external auditors and legal counsel, if necessary, any litigation, claim or other contingency, including tax assessments, that could have a material effect on the financial position or operating results of the corporation, and the manner in which these matters have been disclosed or reflected in the financial statements.

8. | Review with the external auditors any audit problems or difficulties experienced by the external auditors in performing the audit, including any restrictions or limitations imposed by management, and management’s response. Resolve any disagreements between management and the external auditors regarding these matters.

9. | Review the results of the external auditors’ audit work including findings and recommendations, management’s response, and any resulting changes in accounting practices or policies and the impact such changes may have on the financial statements.

10. | Review and discuss with management and the external auditors the audited annual financial statements and related management discussion and analysis, make recommendations to the board with respect to approval thereof, before being released to the public, and obtain an explanation from management of all significant variances between comparable reporting periods.

11. | Review and discuss with management and the external auditors all interim unaudited financial statements and related interim management discussion and analysis and make recommendations to the board with respect to the approval thereof, before being released to the public.

12. | Obtain confirmation from the chief executive officer and the chief financial officer (and considering the external auditors’ comments, if any, thereon) to their knowledge:

| (a) | that the audited financial statements, together with any financial information included in the annual MD&A and annual information form, fairly present in all material respects the corporation’s financial condition, cash flow and results of operation, as of the date and for the periods presented in such filings; and

| (b) | that the interim financial statements, together with any financial information included in the interim MD&A, fairly present in all material respects the corporation’s financial condition, cash flow and results of operation, as of the date and for the periods presented in such filings.

13. | Review news releases to be issued in connection with the audited annual financial statements and related management discussion and analysis and the interim unaudited financial statements and related interim management discussion and analysis, before being released to the public. Discuss the type and presentation of information to be included in news releases (paying particular attention to any use of “pro-forma” or “adjusted” non-GAAP, information).

14. | Review any news release, before being released to the public, containing earnings guidance or financial information based upon the corporation’s financial statements prior to the release of such statements.

15. | Review the appointment of the chief financial officer and have the chief financial officer report to the committee on the qualifications of new key financial executives involved in the financial reporting process.

16. | Consult with the human resources and compensation committee on the succession plan for the chief financial officer and controller. Review the succession plans in respect of the chief financial officer and controller.

Internal Controls

1. | Receive from management a statement of the corporation’s system of internal controls over accounting and financial reporting.

2. | Consider and review with management, the internal auditor and the external auditors, the adequacy and effectiveness of internal controls over accounting and financial reporting within the corporation and any proposed significant changes in them.

3. | Consider and discuss the scope of the internal auditors and external auditors review of the corporation’s internal controls, and obtain reports on significant findings and recommendations, together with management responses.

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4. | Discuss, as appropriate, with management, the external auditors and the internal auditor, any major issues as to the adequacy of the corporation’s internal controls and any special audit steps in light of material internal control deficiencies.

5. | Review annually the disclosure controls and procedures, including (a) the certification timetable and related process and (b) the procedures that are in place for the review of the corporation’s disclosure of financial information extracted from the corporation’s financial statements and the adequacy of such procedures. Receive confirmation from the chief executive officer and the chief financial officer of the effectiveness of disclosure controls and procedures, and whether there are any significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the corporation’s ability to record, process, summarize and report financial information or any fraud, whether or not material, that involves management or other employees who have a significant role in the corporation’s internal control over financial reporting. In addition, receive confirmation from the chief executive officer and the chief financial officer that they are prepared to sign the annual and quarterly certificates required by applicable securities law.

6. | Review management’s annual report and the external auditors’ report on the assessment of the effectiveness of the corporation’s internal control over financial reporting.

7. | Receive a report, at least annually, from the reserves oversight committee of the board on the corporation’s mineral reserves.

External Auditors

(i) | External Auditors’ Qualifications and Selection

1. | Subject to the requirements of applicable law, be solely responsible to select, retain, compensate, oversee, evaluate and, where appropriate, replace the external auditors, who must be registered with agencies mandated by applicable law. The committee shall be entitled to adequate funding from the corporation for the purpose of compensating the external auditors for completing an audit and audit report.

2. | Instruct the external auditors that:

| (a) | they are ultimately accountable to the board and the committee, as representatives of shareholders; and

| (b) | they must report directly to the committee.

3. | Ensure that the external auditors have direct and open communication with the committee and that the external auditors meet regularly with the committee without the presence of management to discuss any matters that the committee or the external auditors believe should be discussed privately.

4. | Evaluate the external auditors’ qualifications, performance, and independence. As part of that evaluation:

| (a) | at least annually, request and review a formal report by the external auditors describing: the firm’s internal quality-control procedures; any material issues raised by the most recent internal quality-control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps taken to deal with any such issues; and (to assess the auditors’ independence) all relationships between the external auditors and the corporation, including the amount of fees received by the external auditors for the audit services and for various types of non-audit services for the periods prescribed by applicable law; and

| (b) | annually review and confirm with management and the external auditors the independence of the external auditors, including the extent of non-audit services and fees, the extent to which the compensation of the audit partners of the external auditors is based upon selling non-audit services, the timing and process for implementing the rotation of the lead audit partner, reviewing partner and other partners providing audit services for the corporation, whether there should be a regular rotation of the audit firm itself, and whether there has been a “cooling off” period of one year for any former employees of the external auditors who are now employees with a financial oversight role, in order to assure compliance with applicable law on such matters; and

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| (c) | annually review and evaluate senior members of the external audit team, including their expertise and qualifications. In making this evaluation, the audit and finance committee should consider the opinions of management and the internal auditor.

Conclusions on the independence of the external auditors should be reported to the board.

5. | Review and approve the corporation’s policies for the corporation’s hiring of employees and former employees of the external auditors. Such policies shall include, at minimum, a one-year hiring “cooling off” period.

(ii) | Other Matters

6. | Meet with the external auditors to review and approve the annual audit plan of the corporation’s financial statements prior to the annual audit being undertaken by the external auditors, including reviewing the year-to-year co-ordination of the audit plan and the planning, staffing and extent of the scope of the annual audit. This review should include an explanation from the external auditors of the factors considered by the external auditors in determining their audit scope, including major risk factors. The external auditors shall report to the committee all significant changes to the approved audit plan.

7. | Review and approve the basis and amount of the external auditors’ fees with respect to the annual audit in light of all relevant matters.

8. | Review and pre-approve all audit and non-audit service engagement fees and terms in accordance with applicable law, including those provided to the subsidiaries of the corporation by the external auditors or any other person in its capacity as external auditors of such subsidiary. Between scheduled committee meetings, the chair of the committee, on behalf of the committee, is authorised to pre-approve any audit or non-audit service engagement fees and terms. At the next committee meeting, the chair shall report to the committee any such pre-approval given. Establish and adopt procedures for such matters.

Internal Auditor

1. | Review and approve the appointment or removal of the internal auditor.

2. | Review and discuss with the external auditors, management, and internal auditor the responsibilities, budget and staffing of the corporation’s internal audit function.

3. | Review and approve the mandate for the internal auditor and the scope of annual work planned by the internal auditor, receive summary reports of internal audit findings, management’s response thereto, and reports on any subsequent follow-up to any identified weakness.

4. | Ensure that the internal auditor has direct and open communication with the committee and that the internal auditor meets regularly with the committee without the presence of management to discuss any matters that the committee or the internal auditor believe should be discussed privately, such as problems or difficulties which were encountered in the course of internal audit work, including restrictions on the scope of activities or access to required information, and any disagreements with management.

5. | Review and discuss with the internal auditor and management the internal auditor’s ongoing assessments of the corporation’s business processes and system of internal controls.

6. | Review the effectiveness of the internal audit function, including staffing, organizational structure and qualifications of the internal auditor and staff.

Compliance

1. | Monitor compliance by the corporation with all payments and remittances required to be made in accordance with applicable law, where the failure to make such payments could render the directors of the corporation personally liable.

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2. | The receipt of regular updates from management regarding compliance with laws and regulations and the process in place to monitor such compliance, excluding, however, legal compliance matters subject to the oversight of the safety, health and environment committee of the board. Review the findings of any examination by regulatory authorities and any external auditors’ observations relating to such matters.

3. | Establish and oversee the procedures in the code of conduct and ethics policy to address:

| (a) | the receipt, retention and treatment of complaints received by the corporation regarding accounting, internal accounting or auditing matters; and

| (b) | confidential, anonymous submissions by employees of concerns regarding questionable accounting and auditing matters.

Receive periodically a summary report from the senior vice-president governance, law and corporate secretary on such matters as required by the code of conduct and ethics.

4. | Review and recommend to the board for approval a code of conduct and ethics for employees, officers and directors of the corporation. Monitor management’s implementation of the code of conduct and ethics and the international business conduct policy and review compliance therewith by, among other things, obtaining an annual report summarizing statements of compliance by employees pursuant to such policies and reviewing the findings of any investigations of non-compliance. Periodically review the adequacy and appropriateness of such policies and make recommendations to the board thereon.

5. | Monitor management’s implementation of the anti-fraud policy; and review compliance therewith by, among other things, receiving reports from management on:

| (a) | any investigations of fraudulent activity;

| (b) | monitoring activities in relation to fraud risks and controls; and

| (c) | assessments of fraud risk.

Periodically review the adequacy and appropriateness of the anti-fraud policy and make recommendations to the board thereon.

6. | Review all proposed related party transactions and situations involving a director’s, senior officer’s or an affiliate’s potential or actual conflict of interest that are not required to be dealt with by an “independent committee” pursuant to securities law rules, other than routine transactions and situations arising in the ordinary course of business, consistent with past practice. Between scheduled committee meetings, the chair of the committee, on behalf of the committee, is authorised to review all such transactions and situations. At the next committee meeting, the chair shall report the results of such review. Ensure that political and charitable donations conform with policies and budgets approved by the board.

7. | Monitor management of hedging, debt and credit, make recommendations to the board respecting policies for management of such risks, and review the corporation’s compliance therewith.

8. | Approve the review and approval process for the expenses submitted for reimbursement by the chief executive officer.

9. | Oversee management’s mitigation of material risks within the committee’s mandate and as otherwise assigned to it by the nominating, corporate governance and risk committee.

Financial Oversight

1. | Assist the board in its consideration and ongoing oversight of matters pertaining to:

| (a) | capital structure and funding including finance and cash flow planning;

| (b) | capital management planning and initiatives;

| (c) | property and corporate acquisitions and divestitures including proposals which may have a material impact on the corporation’s capital position;

| (d) | the corporation’s annual budget and two-year business plan;

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| (e) | the activities of the corporation’s trading group including financial results, compliance with approval limits, any significant breaches of policies, and risk measures on significant positions and the portfolio in aggregate;

| (f) | the corporation’s insurance program;

| (g) | directors’ and officers’ liability insurance and indemnity agreements; and

| (h) | matters the board may refer to the committee from time to time in connection with the corporation’s capital position.

Organizational matters

1. | The procedures governing the committee shall, except as otherwise provided for herein, be those applicable to the board committees as set forth in Part 7 of the General Bylaws of the corporation.

2. | The members and the chair of the committee shall be entitled to receive remuneration for acting in such capacity as the board may from time to time determine.

3. | The committee shall have the resources and authority appropriate to discharge its duties and responsibilities, including the authority to:

| (a) | select, retain, terminate, set and approve the fees and other retention terms of special or independent counsel, accountants or other experts, as it deems appropriate; and

| (b) | obtain appropriate funding to pay, or approve the payment of, such approved fees;

without seeking approval of the board or management.

4. | Any member of the committee may be removed or replaced at any time by the board and shall cease to be a member of the committee upon ceasing to be a director. The board may fill vacancies on the committee by appointment from among its members. If and whenever a vacancy shall exist on the committee, the remaining members may exercise all its powers so long as a quorum remains in office. Subject to the foregoing, each member of the committee shall remain as such until the next annual meeting of shareholders after that member’s election.

5. | The committee shall annually review and assess the adequacy of its mandate and recommend any proposed changes to the nominating, corporate governance and risk committee for recommendation to the board for approval.

6. | The committee shall participate in an annual performance evaluation, the results of which will be reviewed by the board.

7. | The committee shall perform any other activities consistent with this mandate, the corporation’s governing laws and the regulations of stock exchanges, as the committee or the board deems necessary or appropriate.

8. | A standing invitation will be issued to all non-executive directors to attend the financial oversight portion of each committee meeting.

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