40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 40-F

ANNUAL REPORT PURSUANT TO SECTION 13(a) or 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2013

Commission file number: 1-14228

CAMECO CORPORATION

(Exact name of Registrant as specified in its charter)

CANADA

(Province or other jurisdiction of incorporation or organization)

1090

(Primary Standard Industrial Classification Code Number)

98-0113090

(I.R.S. Employer Identification)

2121 - 11th Street West, Saskatoon, Saskatchewan, Canada, S7M 1J3, Telephone: (306) 956-6200

(Address and telephone number of Registrant’s principal executive offices)

James Dobchuk, Cameco Inc., One Southwest Crossing, Suite 210, 11095 Viking Drive

Eden Prairie, Minnesota, USA, 55344, Telephone: (952) 941-2470

(Name, address, (including zip code) and telephone number (including area code) of agent for service in the United States)

Securities registered pursuant to Section 12(b) of the Act:

Title of Class: Common Shares, no par value

Name of Exchange where Securities are listed: New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

Information filed with this Form:

x   Annual Information Form x   Audited annual financial statements

Number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:

395, 477, 230 Common Shares outstanding as of December 31, 2013

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

x  Yes            ¨  No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files).

¨  Yes            ¨  No

Certain statements in this Form 40-F constitute “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995. In Exhibit 99.1 see “Caution Regarding Forward-Looking Information and Statements”.

Certifications and Disclosure Regarding Controls and Procedures.

(a) Certifications regarding controls and procedures. See Exhibits 99.9 and 99.10.

(b) Evaluation of disclosure controls and procedures. As of December 31, 2013 an evaluation of the effectiveness of Cameco Corporation’s “disclosure controls and procedures” (as such term is defined in Rules 13a-15(e) and 15d-15(e) of the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”)), was carried out by Cameco Corporation’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”). Based on that evaluation, the CEO and CFO have concluded that as of such date Cameco Corporation’s disclosure controls and procedures are effective to provide a reasonable level of assurance that information required to be disclosed by Cameco Corporation in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in United States Securities and Exchange Commission (the “Commission”) rules and forms.

It should be noted that while the CEO and CFO believe that Cameco Corporation’s disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect the disclosure controls and procedures or internal control over financial reporting to be capable of preventing all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

(c) Management’s annual report on internal control over financial reporting. Management, including Cameco Corporation’s CEO and CFO, is responsible for establishing and maintaining adequate internal control over financial reporting (as that term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) for Cameco Corporation. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Cameco Corporation’s internal control over financial reporting was effective as of December 31, 2013.

(d) Attestation report of the registered public accounting firm. The effectiveness of Cameco Corporation’s internal control over financial reporting as of December 31, 2013 was audited by KPMG LLP, an independent registered public accounting firm, as stated in their report in Exhibit 99.6 – Report of Independent Registered Public Accounting Firm.

(e) Changes in internal control over financial reporting. During the fiscal year ended December 31, 2013, there were no changes in Cameco Corporation’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, Cameco Corporation’s internal control over financial reporting.

Audit & Finance Committee Financial Expert. Cameco Corporation’s board of directors has determined that at least two of the members of its audit and finance committee (the “audit committee”) are audit committee financial experts. The audit committee financial experts are John Clappison and Ian Bruce. Mr. Bruce has been determined by Cameco Corporation’s board of directors to be an independent director as such term is defined under the Canadian Securities Administrators’ National Instrument 52-110 (Audit Committees) (“NI 52-110”), the Commission’s audit committee independence requirements, and the rules of the New York Stock Exchange relating to the independence of audit committee members.

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Mr. Clappison has been determined to be an independent director by Cameco Corporation’s board of directors under NI 52-110, which is the Canadian corporate governance rule that applies to Cameco Corporation, and under the Commission’s audit committee independence requirements. However, Mr. Clappison’s son-in-law is a partner at KPMG LLP, the auditors of Cameco Corporation, and therefore Mr. Clappison is deemed to be a non-independent director as such term is used in the rules of the New York Stock Exchange. Mr. Clappison’s son-in-law is prohibited from being engaged in the Cameco Corporation audit. Under the rules of the Commission and the Public Company Accounting Oversight Board (United States), such relationship does not impair the independence of KPMG LLP.

Information concerning the relevant experience of Mr. Clappison and Mr. Bruce is included in their biographical information contained in Cameco Corporation’s Annual Information Form in Exhibit 99.1. The Commission has indicated that the designation of a person as an audit committee financial expert does not make such person an “expert” for any purpose, impose any duties, obligations or liability on such person that are greater than those imposed on members of the audit committee and board of directors who do not carry this designation, or affect the duties, obligations or liability of any other member of the audit committee or board of directors.

Code of Ethics. Cameco Corporation’s code of conduct and ethics (the “Code”) is applicable to all directors, officers and employees of Cameco Corporation, including the CEO and CFO. The Code, as well as Cameco Corporation’s corporate governance practices and mandates of the board of directors and its committees, and position descriptions for the chief executive officer and the non-executive chair, can be found on Cameco Corporation’s website at www.cameco.com under “Responsibility—Governance” and are also available in print to any shareholder upon request. Since the adoption of the Code, there have not been any waivers, including implied waivers, from any provision of the Code. In 2013, we amended our previously filed Code to provide for:

• updates to titles, names of departments and names of policies and programs; and

• discussion on the Nuclear Technology Import and Export Compliance Controls Program

The Code was furnished to the Commission on February 6, 2014 as Exhibit 1 to a report on Form 6-K and is incorporated by reference herein as Exhibit 99.21.

Principal Accountant Fees and Services. See Exhibit 99.4.

Off-Balance Sheet Arrangements. In the normal course of operations, Cameco Corporation enters into certain transactions that are not required to be recorded on its balance sheet. These activities include the issuing of financial assurances and long-term product purchase contracts. These arrangements are disclosed in the following sections of Exhibit 99.3 – 2013 Management’s Discussion and Analysis and the notes for Exhibit No 99.2 – 2013 Consolidated Audited Financial Statements:

(a) Financial assurances. In the 2013 Management’s Discussion and Analysis, see the disclosure at “Off-balance sheet arrangements” (pages 39-40). In the 2013 Consolidated Audited Financial Statements, see the disclosure at notes 12 and 15 of the financial statements.

(b) Long-term product purchase contracts. In the 2013 Management’s Discussion and Analysis, see the disclosure at “Off-balance sheet arrangements” (pages 39-40).

Tabular Disclosure of Contractual Obligations. See Exhibit 99.5.

Identification of the Audit Committee. Cameco Corporation has a separately-designated standing audit committee established in accordance with Section 3(a)(58)(A) of the Exchange Act. Cameco Corporation’s audit committee is comprised of: John Clappison (chair), Ian Bruce, Daniel Camus, Nancy Hopkins and Anne McLellan.

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Audited Annual Financial Statements. Cameco Corporation’s Consolidated Audited Financial Statements as at December 31, 2013 and 2012, including the related report of the independent registered public accounting firm, is included in Exhibit 99.7 – Report of Independent Registered Public Accounting Firm – Public Company Accounting Oversight Board (United States) Standards.

Mine Safety Disclosure. Neither Cameco Corporation nor any of its subsidiaries is the “operator” of any “coal or other mine”, as those terms are defined in section 3 of the Federal Mine Safety and Health Act of 1977 (30 U.S.C. 802), that is subject to the provisions of such Act (30 U.S.C. 801 et seq.). Therefore, the provisions of Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 16 of General Instruction B to Form 40-F requiring disclosure concerning mine safety violations and other regulatory matters do not apply to Cameco Corporation or any of its subsidiaries or U.S. mines.

Disclosure Pursuant to the Requirements of the New York Stock Exchange.

(a) Corporate governance practices. Disclosure of the significant ways in which Cameco Corporation’s corporate governance practices differ from those required for U.S. companies under the NYSE listing standards can be found on Cameco Corporation’s website at www.cameco.com under “Responsibility – Governance”.

(b) Presiding director at meetings of non-management directors. Cameco Corporation schedules regular director sessions in which Cameco Corporation’s “non-management directors” (as that term is defined in the rules of the NYSE) meet without management participation. Mr. Neil McMillan, as non-executive chair of Cameco Corporation, serves as the presiding director (the “Presiding Director”) at such sessions. Each of Cameco Corporation’s non-management directors is “independent” as such term is used in the rules of the NYSE with the exception of Donald Deranger and John Clappison. Cameco Corporation’s criteria for director independence are set out as Appendix “A” to its board mandate, which can be found on Cameco Corporation’s website at www.cameco.com under “Responsibility – Governance”.

(c) Communication with non-management directors. Shareholders may send communications to Cameco Corporation’s Presiding Director or non-management directors by mailing (by regular mail or other means of delivery) to the corporate head office at 2121 – 11^th Street West, Saskatoon, Saskatchewan, Canada, S7M 1J3 a sealed envelope marked “Private and Strictly Confidential-Attention: Chair of the Board of Directors of Cameco Corporation”. Any such envelope will be delivered unopened to the Presiding Director for appropriate action. The status of all outstanding concerns addressed to the Presiding Director will be reported to the board of directors as appropriate.

(d) Corporate governance guidelines. According to Section 303A.09 of the NYSE Listed Company Manual, a listed company must adopt and disclose a set of corporate governance guidelines with respect to specified topics. Such guidelines and the charters of the listed company’s most important committees of the board of directors are required to be posted on the listed company’s website and be available in print to any shareholder upon request. Cameco Corporation operates under corporate governance guidelines that are consistent with the requirements of Section 303A.09 of the NYSE Listed Company Manual. Cameco Corporation’s corporate governance guidelines and the charters of its most important committees of the board of directors can be found at Cameco Corporation’s website at www.cameco.com under “Responsibility – Governance” and are available in print to any shareholder who requests them.

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(e) Independent directors. The names of Cameco Corporation’s non-management directors are: Ian Bruce; Daniel Camus; Joe Colvin; James Curtiss; Donald Deranger; Catherine Gignac; James Gowans; Nancy Hopkins; Anne McLellan; Neil McMillan; and Victor Zaleschuk. Each of the non-management directors is “independent”, as such term is used in the rules of the NYSE with the exception of Donald Deranger and John Clappison.

(f) Audit committee. Daniel Camus is a member of the audit committees of three other publicly traded companies. The board of directors has determined that such simultaneous service will not impair the ability of Mr. Camus to effectively serve on Cameco Corporation’s audit committee.

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EXHIBIT INDEX

Exhibit No.	Description
99.1	2013 Annual Information Form
99.2	2013 Consolidated Audited Financial Statements
99.3	2013 Management’s Discussion and Analysis
99.4	Principal Accountant Fees and Services
99.5	Tabular Disclosure of Contractual Obligations
99.6	Report of Independent Registered Public Accounting Firm – Internal Control Over Financial Reporting
99.7	Report of Independent Registered Public Accounting Firm – Public Company Accounting Oversight Board (United States) Standards
99.8	Consent of Independent Registered Public Accounting Firm
99.9	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the U.S. Securities Exchange Act of 1934, as amended
99.10	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the U.S. Securities Exchange Act of 1934, as amended
99.11	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.12	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.13	Consent of Alain G. Mainville, P. Geo.
99.14	Consent of Ken Gullen, P. Eng.

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99.15	Consent of Lawrence Reimann, P. Eng.
99.16	Consent of Eric Paulsen, P. Eng., Pr. Eng.
99.17	Consent of C. Scott Bishop, P. Eng.
99.18	Consent of Gregory M. Murdock, P. Eng.
99.19	Consent of David Bronkhorst, P. Eng.
99.20	Consent of Leslie (Les) D. Yesnik, P. Eng.
99.21	Code of Conduct and Ethics (as amended and restated as of October 2013) (incorporated by reference to Cameco Corporation’s Form 6-K, furnished to the Commission on February 6, 2014)

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UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

Undertaking

Cameco Corporation undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

Consent to Service of Process

Cameco Corporation has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises.

Any change to the name or address of the agent for service of process of Cameco Corporation shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of the relevant registration statement.

SIGNATURES

Pursuant to the requirements of the Exchange Act, Cameco Corporation certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.

DATED this 27^th day of February, 2014.

CAMECO CORPORATION
By:	/s/ Grant Isaac
	Name: Grant Isaac
	Title: Senior Vice-President and
	Chief Financial Officer

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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 – 11^th 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.

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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.

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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

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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)

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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.

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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.

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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.

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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.

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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.

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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.

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Uranium – operating properties

	Inkai Inkai is a very significant uranium deposit, located in Kazakhstan. There are two production areas (blocks 1 and 2) and an exploration area (block 3). The operator is Joint Venture Inkai Limited Liability Partnership, which we jointly own (60%) with Kazatomprom (40%). Inkai is one of our three material uranium properties.
Location	South Kazakhstan
Ownership	60%
End product	uranium concentrates
Certifications	BSI OHSAS 18001
	ISO 14001 certified
Estimated 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.

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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

2013 ANNUAL INFORMATION FORM    Page 54

• 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.

2013 ANNUAL INFORMATION FORM    Page 57

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.

2013 ANNUAL INFORMATION FORM    Page 63

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.

2013 ANNUAL INFORMATION FORM    Page 68

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.

2013 ANNUAL INFORMATION FORM    Page 69

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.

2013 ANNUAL INFORMATION FORM    Page 72

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:

2013 ANNUAL INFORMATION FORM    Page 75

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.

2013 ANNUAL INFORMATION FORM    Page 77

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.

2013 ANNUAL INFORMATION FORM    Page 78

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.

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• 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.

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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.

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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 15^th 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.

2012 ANNUAL INFORMATION FORM    Page 135

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.

2012 ANNUAL INFORMATION FORM    Page 136

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

2012 ANNUAL INFORMATION FORM    Page 137

(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.

2012 ANNUAL INFORMATION FORM    Page 138

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;

2012 ANNUAL INFORMATION FORM    Page 139

(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.

2012 ANNUAL INFORMATION FORM    Page 140

EX-99.2

EXHIBIT 99.2

Cameco Corporation

2013 Consolidated Audited Financial Statements

February 7, 2014

Cameco Corporation

2013 consolidated financial statements

February 7, 2014

Report of management’s accountability

The accompanying consolidated financial statements have been prepared by management in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board. Management is responsible for ensuring that these statements, which include amounts based upon estimates and judgments, are consistent with other information and operating data contained in the annual financial review and reflect the corporation’s business transactions and financial position.

Management is also responsible for the information disclosed in the management’s discussion and analysis including responsibility for the existence of appropriate information systems, procedures and controls to ensure that the information used internally by management and disclosed externally is complete and reliable in all material respects.

In addition, management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. The internal control system includes an internal audit function and a code of conduct and ethics, which is communicated to all levels in the organization and requires all employees to maintain high standards in their conduct of the corporation’s affairs. Such systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate and that the Company’s assets are appropriately accounted for and adequately safeguarded. Management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the criteria established in “Internal Control – Integrated Framework (1992)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s system of internal control over financial reporting was effective as at December 31, 2013.

KPMG LLP has audited the consolidated financial statements in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States).

The board of directors annually appoints an audit committee comprised of directors who are not employees of the corporation. This committee meets regularly with management, the internal auditor and the shareholders’ auditors to review significant accounting, reporting and internal control matters. Both the internal and shareholders’ auditors have unrestricted access to the audit committee. The audit committee reviews the consolidated financial statements, the report of the shareholders’ auditors, and the management’s discussion and analysis and submits its report to the board of directors for formal approval.

Original signed by Tim S. Gitzel	Original signed by Grant E. Isaac
President and Chief Executive Officer	Senior Vice-President and Chief Financial Officer
February 7, 2014	February 7, 2014

2

Independent auditors’ report

To the Shareholders and Board of Directors of Cameco Corporation:

We have audited the accompanying consolidated financial statements of Cameco Corporation, which comprise the consolidated statements of financial position as at December 31, 2013, December 31, 2012 and January 1, 2012, the consolidated statements of earnings, statements of comprehensive income, changes in equity and cash flows for the years ended December 31, 2013 and December 31, 2012, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s responsibility for the consolidated financial statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Cameco Corporation as at December 31, 2013, December 31, 2012 and January 1, 2012, and its consolidated financial performance and its consolidated cash flows for the years ended December 31, 2013 and December 31, 2012 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Comparative information

Without modifying our opinion, we draw attention to Note 3 to the consolidated financial statements which indicates that the comparative information presented as at and for the year ended December 31, 2012, has been revised and that the comparative information presented as at January 1, 2012 has been derived from the consolidated financial statements as at and for the year ended December 31, 2011.

Original signed by KPMG LLP

Chartered Accountants

February 7, 2014

Saskatoon, Canada

3

Consolidated statements of earnings

For the years ended December 31						(Revised - note 3)
($Cdn thousands, except per share amounts)	Note		2013			2012
Revenue from products and services			$	2,438,723		$	1,890,660
Cost of products and services sold				1,549,238			1,133,263
Depreciation and amortization				282,756			217,381
Cost of sales				1,831,994			1,350,644
Gross profit				606,729			540,016
Administration				184,976			180,900
Impairment charges		9		70,159			168,000
Exploration				72,833			97,260
Research and development				7,302			9,301
Loss (gain) on sale of assets				6,766			(1,660	)
Earnings from operations				264,693			86,215
Finance costs		20		(62,121	)		(67,654	)
Gains (losses) on derivatives		27		(61,970	)		41,416
Finance income				6,967			13,934
Share of earnings from BPLP		12		109,553			157,846
Share of loss from equity-accounted investees		12		(10,867	)		(5,896	)
Other expense		21		(18,326	)		(24,746	)
Earnings before income taxes				227,929			201,115
Income tax recovery		22		(89,758	)		(50,641	)
Net earnings			$	317,687		$	251,756
Net earnings (loss) attributable to:
Equity holders			$	318,495		$	253,309
Non-controlling interest				(808	)		(1,553	)
Net earnings			$	317,687		$	251,756
Earnings per common share attributable to equity holders
Basic		23	$	0.81		$	0.64
Diluted		23	$	0.81		$	0.64

See accompanying notes to consolidated financial statements.

4

Consolidated statements of comprehensive income

For the years ended December 31						(Revised - note 3)
($Cdn thousands)	Note		2013			2012
Net earnings			$	317,687		$	251,756
Other comprehensive income (loss), net of taxes		22
Items that will not be reclassified to net earnings:
Remeasurements of defined benefit liability				1,870			181
Remeasurements of defined benefit liability—equity-accounted investees				239,915			(54,794	)
Items that are or may be reclassified to net earnings:
Exchange differences on translation of foreign operations				(10,792	)		(23,287	)
Gains on derivatives designated as cash flow hedges—equity-accounted investees				190			3,982
Gains on derivatives designated as cash flow hedges transferred to net earnings—equity-accounted investees				(3,982	)		(19,450	)
Unrealized gains (losses) on available-for-sale assets				28			(19	)
Gains on available-for-sale assets transferred to net earnings				—			(129	)
Other comprehensive income (loss), net of taxes				227,229			(93,516	)
Total comprehensive income			$	544,916		$	158,240
Other comprehensive income (loss) attributable to:
Equity holders			$	227,157		$	(93,396	)
Non-controlling interest				72			(120	)
Other comprehensive income (loss) for the period			$	227,229		$	(93,516	)
Total comprehensive income (loss) attributable to:
Equity holders			$	545,652		$	159,913
Non-controlling interest				(736	)		(1,673	)
Total comprehensive income for the period			$	544,916		$	158,240

See accompanying notes to consolidated financial statements.

5

Consolidated statements of financial position

As at December 31						(Revised - note 3)		(Revised - note 3)
($Cdn thousands)	Note		2013			2012		Jan 1/12
Assets
Current assets
Cash and cash equivalents			$	229,135		$	749,499	$	395,552
Short-term investments				—			49,535		804,141
Accounts receivable		7		431,375			404,040		516,663
Current tax assets				2,598			9,404		17,988
Inventories		8		913,315			563,578		493,875
Supplies and prepaid expenses				177,632			110,777		114,182
Current portion of long-term receivables, investments and other		11		3,775			22,807		14,088
Total current assets				1,757,830			1,909,640		2,356,489
Property, plant and equipment		9		5,040,993			4,817,150		3,907,655
Goodwill and intangible assets		10		194,031			93,101		97,728
Long-term receivables, investments and other		11		287,548			211,358		188,718
Investments in equity-accounted investees		12		492,712			205,889		224,148
Deferred tax assets		22		266,203			193,916		82,223
Total non-current assets				6,281,487			5,521,414		4,500,472
Total assets			$	8,039,317		$	7,431,054	$	6,856,961
Liabilities and shareholders’ equity
Current liabilities
Bank overdraft		14	$	41,226		$	—	$	—
Accounts payable and accrued liabilities		13		437,941			387,653		355,634
Current tax liabilities				54,708			36,600		39,330
Short-term debt		14		50,230			67,090		79,186
Dividends payable				39,548			39,535		39,475
Current portion of other liabilities		16		60,685			13,028		32,508
Current portion of provisions		17		20,213			18,830		14,857
Total current liabilities				704,551			562,736		560,990
Long-term debt		15		1,293,383			1,292,440		795,145
Other liabilities		16		79,380			77,517		52,308
Provisions		17		570,700			550,624		519,625
Deferred tax liabilities		22		41,909			5,773		8,165
Total non-current liabilities				1,985,372			1,926,354		1,375,243
Shareholders’ equity
Share capital				1,854,671			1,851,507		1,842,289
Contributed surplus				186,382			168,952		155,757
Retained earnings				3,314,049			2,913,134		2,872,565
Other components of equity				(6,837	)		7,791		46,574
Total shareholders’ equity attributable to equity holders				5,348,265			4,941,384		4,917,185
Non-controlling interest				1,129			580		3,543
Total shareholders’ equity				5,349,394			4,941,964		4,920,728
Total liabilities and shareholders’ equity			$	8,039,317		$	7,431,054	$	6,856,961

Commitments and contingencies [notes 17, 22]

See accompanying notes to consolidated financial statements.

Approved by the board of directors

Original signed by Tim S. Gitzel and John H. Clappison

6

Consolidated statements of changes in equity

																								(Revised - note 3)
	Attributable to equity holders
($Cdn thousands)	Share capital		Contributed surplus			Retained earnings			Foreign currency translation			Cash flow hedges			Available-for- sale assets			Total			Non- controlling interest			Total equity
Balance at January 1, 2013	$	1,851,507	$	168,952		$	2,913,134		$	3,699		$	4,092		$	—		$	4,941,384		$	580		$	4,941,964
Net earnings (loss)		—		—			318,495			—			—			—			318,495			(808	)		317,687
Other comprehensive income		—		—			241,785			(10,864	)		(3,792	)		28			227,157			72			227,229
Total comprehensive income for the year		—		—			560,280			(10,864	)		(3,792	)		28			545,652			(736	)		544,916
Share-based compensation		—		19,008			—			—			—			—			19,008			—			19,008
Share options exercised		3,164		(1,578	)		—			—			—			—			1,586			—			1,586
Dividends		—		—			(158,177	)		—			—			—			(158,177	)		—			(158,177	)
Acquisition of non-controlling interest in subsidiary		—		—			—			—			—			—			—			97			97
Change in ownership interest in subsidiary		—		—			(1,188	)		—			—			—			(1,188	)		1,188			—
Balance at December 31, 2013	$	1,854,671	$	186,382		$	3,314,049		$	(7,165	)	$	300		$	28		$	5,348,265		$	1,129		$	5,349,394
Balance at January 1, 2012	$	1,842,289	$	155,757		$	2,872,565		$	26,866		$	19,560		$	148		$	4,917,185		$	3,543		$	4,920,728
Net earnings (loss)		—		—			253,309			—			—			—			253,309			(1,553	)		251,756
Other comprehensive loss		—		—			(54,613	)		(23,167	)		(15,468	)		(148	)		(93,396	)		(120	)		(93,516	)
Total comprehensive income for the year		—		—			198,696			(23,167	)		(15,468	)		(148	)		159,913			(1,673	)		158,240
Share-based compensation		—		17,550			—			—			—			—			17,550			—			17,550
Share options exercised		9,218		(4,355	)		—			—			—			—			4,863			—			4,863
Dividends		—		—			(158,127	)		—			—			—			(158,127	)		—			(158,127	)
Change in ownership interest in subsidiary		—		—			—			—			—			—			—			(1,290	)		(1,290	)
Balance at December 31, 2012	$	1,851,507	$	168,952		$	2,913,134		$	3,699		$	4,092		$	—		$	4,941,384		$	580		$	4,941,964

See accompanying notes to consolidated financial statements.

7

Consolidated statements of cash flows

For the years ended December 31						(Revised - note 3)
($Cdn thousands)	Note		2013			2012
Operating activities
Net earnings			$	317,687		$	251,756
Adjustments for:
Depreciation and amortization				282,756			217,381
Deferred charges				48,041			(2,910	)
Unrealized losses (gains) on derivatives				39,059			(24,117	)
Share-based compensation		25		19,008			17,550
Loss (gain) on sale of assets				6,766			(1,660	)
Finance costs		20		62,121			67,654
Finance income				(6,967	)		(13,934	)
Share of earnings from BPLP				(109,553	)		(157,846	)
Share of loss from equity-accounted investees		12		10,867			5,896
Impairment charge on non-producing property		9		70,159			168,000
Other expense (income)		21		18,326			(4,796	)
Income tax recovery		22		(89,758	)		(50,641	)
Interest received				6,089			15,517
Income taxes paid				(107,350	)		(54,475	)
Income taxes refunded				10,993			18,569
BPLP net distributions				91,166			114,392
Other operating items		24		(139,526	)		13,116
Net cash provided by operations				529,884			579,452
Investing activities
Additions to property, plant and equipment		9		(645,651	)		(671,530	)
Acquisitions, net of cash		6		(133,924	)		(576,408	)
Repayment of debt acquired on acquisition of business				(118,068	)		—
Decrease in short-term investments				49,535			754,434
Increase in long-term receivables, investments and other				(6,373	)		(26,145	)
Proceeds from sale of property, plant and equipment				67			3,315
Net cash used in investing				(854,414	)		(516,334	)
Financing activities
Increase in debt				14,655			521,570
Decrease in debt				(33,114	)		(35,629	)
Interest paid				(65,908	)		(43,521	)
Proceeds from issuance of shares, stock option plan				2,475			7,033
Dividends paid				(158,165	)		(158,066	)
Net cash provided by (used in) financing				(240,057	)		291,387
Increase (decrease) in cash and cash equivalents net of bank overdraft, during the year				(564,587	)		354,505
Exchange rate changes on foreign currency cash balances				2,997			(558	)
Cash and cash equivalents net of bank overdraft, beginning of year				749,499			395,552
Cash and cash equivalents net of bank overdraft at end of year			$	187,909		$	749,499
Cash and cash equivalents is comprised of:
Cash			$	59,183		$	204,369
Cash equivalents				169,952			545,130
Cash and cash equivalents			$	229,135		$	749,499
Bank overdraft				(41,226	)		—
Cash and cash equivalents and bank overdraft			$	187,909		$	749,499

See accompanying notes to consolidated financial statements.

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Notes to consolidated financial statements

For the years ended December 31, 2013 and 2012

1. Cameco Corporation

Cameco Corporation is incorporated under the Canada Business Corporations Act. The address of its registered office is 2121 11th Street West, Saskatoon, Saskatchewan, S7M 1J3. The consolidated financial statements as at and for the year ended December 31, 2013 comprise Cameco Corporation and its subsidiaries (collectively, the Company or Cameco) and the Company’s interests in associates and joint arrangements. The Company is primarily engaged in the exploration for and the development, mining, refining, conversion, fabrication and trading of uranium for sale as fuel for generating electricity in nuclear power reactors in Canada and other countries. Cameco has a 31.6% interest in Bruce Power L.P. (BPLP), which operates the four Bruce B nuclear reactors in Ontario.

2. Significant accounting policies

A. Statement of compliance

These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).

These consolidated financial statements were authorized for issuance by the Company’s board of directors on February 7, 2014.

B. Basis of presentation

These consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. All financial information is presented in Canadian dollars and amounts presented in tabular format have been rounded to the nearest thousand except per share amounts and where otherwise noted.

The consolidated financial statements have been prepared on the historical cost basis except for the following material items which are measured on an alternative basis at each reporting date:

Derivative financial instruments at fair value through profit and loss	Fair value
Non-derivative financial instruments at fair value through profit and loss	Fair value
Available-for-sale financial assets	Fair value
Liabilities for cash-settled share-based payment arrangements	Fair value
Net defined benefit liability	Fair value of plan assets less the present value of the defined benefit obligation

The preparation of the consolidated financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, revenue and expenses. Actual results may vary from these estimates.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. The areas involving a higher degree of judgment or complexity, or areas where assumptions and estimates are significant to the consolidated financial statements are disclosed in note 5.

This summary of significant accounting policies is a description of the accounting methods and practices that have been used in the preparation of these consolidated financial statements and is presented to assist the reader in interpreting the statements contained herein. These accounting policies have been applied consistently to all entities within the consolidated group.

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C. Consolidation principles

i. Business combinations

The acquisition method of accounting is used to account for the acquisition of subsidiaries by the Company. The Company measures goodwill at the acquisition date as the fair value of the consideration transferred, including the recognized amount of any non-controlling interests in the acquiree, less the net recognized amount (generally fair value) of the identifiable assets acquired and liabilities assumed, all measured as of the acquisition date. When the excess is negative, a bargain purchase gain is recognized immediately in earnings. In a business combination achieved in stages, the acquisition date fair value of the Company’s previously held equity interest in the acquiree is also considered in computing goodwill.

Consideration transferred includes the fair values of the assets transferred, liabilities incurred and equity interests issued by the Company. Consideration also includes the fair value of any contingent consideration and share-based compensation awards that are replaced mandatorily in a business combination.

The Company elects on a transaction-by-transaction basis whether to measure any non-controlling interest at fair value, or at their proportionate share of the recognized amount of the identifiable net assets of the acquiree, at the acquisition date.

Acquisition-related costs are expensed as incurred, except for those costs related to the issue of debt or equity instruments. Transaction costs arising on the issue of equity instruments are recognized directly in equity. Transaction costs that are directly related to the probable issuance of a security that is classified as a financial liability is deducted from the amount of the financial liability when it is initially recognized, or recognized in earnings when the issuance is no longer probable.

ii. Subsidiaries

The consolidated financial statements include the accounts of Cameco and its subsidiaries. Subsidiaries are entities over which the Company has control. Subsidiaries are fully consolidated from the date on which control is transferred to the Company and are deconsolidated from the date that control ceases.

iii. Investments in equity-accounted investees

Cameco’s investments in equity-accounted investees include investments in associates and joint ventures.

Associates are those entities over which the Company has significant influence, but not control or joint control, over the financial and operating policies. Significant influence is presumed to exist when the Company holds between 20% and 50% of the voting power of another entity, but can also arise where the Company holds less than 20% if it has the power to be actively involved and influential in policy decisions affecting the entity.

Investments in associates are accounted for using the equity method. The equity method involves the recording of the initial investment at cost and the subsequent adjusting of the carrying value of the investment for Cameco’s proportionate share of the earnings or loss and any other changes in the associates’ net assets, such as dividends. The cost of the investment includes transaction costs.

Adjustments are made to align the accounting policies of the associate with those of the Company before applying the equity method. When the Company’s share of losses exceeds its interest in an equity-accounted investee, the carrying amount of that interest is reduced to zero, and the recognition of further losses is discontinued except to the extent that the Company has incurred legal or constructive obligations or made payments on behalf of the associate. If the associate subsequently reports profits, Cameco resumes recognizing its share of those profits only after its share of the profits equals the share of losses not recognized.

iv. Joint arrangements

A joint arrangement can take the form of a joint operation or joint venture. All joint arrangements involve a contractual arrangement that establishes joint control.

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A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. A joint operation may or may not be structured through a separate vehicle. These arrangements involve joint control of one or more of the assets acquired or contributed for the purpose of the joint operation. The consolidated financial statements of the Company include its share of the assets in such joint operations, together with its share of the liabilities, revenues and expenses arising jointly or otherwise from those operations. All such amounts are measured in accordance with the terms of each arrangement.

A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. A joint venture is always structured through a separate vehicle. It operates in the same way as other entities, controlling the assets of the joint venture, earning its own revenue and incurring its own liabilities and expenses. Interests in joint ventures are accounted for using the equity method of accounting, whereby the Company’s proportionate interest in the assets, liabilities, revenues and expenses of jointly controlled entities are recognized on a single line in the consolidated statements of financial position and consolidated statements of earnings. The share of joint ventures results is recognized in the Company’s consolidated financial statements from the date that joint control commences until the date at which it ceases.

v. Transactions eliminated on consolidation

Intra-group balances and transactions, and any unrealized income and expenses arising from intra-group transactions, are eliminated in preparing the consolidated financial statements. Unrealized gains arising from transactions with equity-accounted investees are eliminated against the investment to the extent of the Company’s interest in the investee. Unrealized losses are eliminated in the same manner as unrealized gains, but only to the extent that there is no evidence of impairment.

D. Foreign currency translation

Items included in the financial statements of each of Cameco’s subsidiaries, associates and joint arrangements are measured using their functional currency, which is the currency of the primary economic environment in which the entity operates. The consolidated financial statements are presented in Canadian dollars, which is Cameco’s functional and presentation currency.

i. Foreign currency transactions

Foreign currency transactions are translated into the respective functional currency of the Company and its entities using the exchange rates prevailing at the dates of the transactions. At the reporting date, monetary assets and liabilities denominated in foreign currencies are translated to the functional currency at the exchange rate at that date. Non-monetary items that are measured in terms of historical cost in a foreign currency are translated using the exchange rate at the date of the transaction. The applicable exchange gains and losses arising on these transactions are reflected in earnings with the exception of foreign exchange gains or losses on provisions for decommissioning and reclamation activities that are in a foreign currency, which are capitalized in property, plant and equipment.

ii. Foreign operations

The assets and liabilities of foreign operations, including goodwill and fair value adjustments arising on acquisition, are translated to Canadian dollars at exchange rates at the reporting dates. The revenues and expenses of foreign operations are translated to Canadian dollars at exchange rates at the dates of the transactions.

Foreign currency differences are recognized in other comprehensive income. When a foreign operation is disposed of, in whole or in part, the relevant amount in the foreign currency translation account is transferred to earnings as part of the gain or loss on disposal.

When the settlement of a monetary item receivable from or payable to a foreign operation is neither planned nor likely in the foreseeable future, foreign exchange gains and losses arising from such a monetary item are considered to form part of the net investment in a foreign operation, and are recognized in other comprehensive income and presented within equity in the foreign currency translation account.

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E. Cash and cash equivalents

Cash and cash equivalents consists of balances with financial institutions and investments in money market instruments, which have a term to maturity of three months or less at the time of purchase.

F. Short-term investments

Short-term investments are comprised of money market instruments with terms to maturity between three and 12 months.

G. Inventories

Inventories of broken ore, uranium concentrates, and refined and converted products are measured at the lower of cost and net realizable value.

Cost includes direct materials, direct labour, operational overhead expenses and depreciation. Net realizable value is the estimated selling price in the ordinary course of business, less the estimated costs of completion and selling expenses.

Consumable supplies and spares are valued at the lower of cost or replacement value.

H. Property, plant and equipment

i. Buildings, plant and equipment and other

Items of property, plant and equipment are measured at cost less accumulated depreciation and impairment charges. The cost of self-constructed assets includes the cost of materials and direct labour, borrowing costs and any other costs directly attributable to bringing the assets to the location and condition necessary for them to be capable of operating in the manner intended by management, including the initial estimate of the cost of dismantling and removing the items and restoring the site on which they are located.

When components of an item of property, plant and equipment have different useful lives, they are accounted for as separate items of property, plant and equipment and depreciated separately.

Gains and losses on disposal of an item of property, plant and equipment are determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment, and are recognized in earnings.

ii. Mineral properties and mine development costs

The decision to develop a mine property within a project area is based on an assessment of the commercial viability of the property, the availability of financing and the existence of markets for the product. Once the decision to proceed to development is made, development and other expenditures relating to the project area are deferred as part of assets under construction and disclosed as a component of property, plant and equipment with the intention that these will be depreciated by charges against earnings from future mining operations. No depreciation is charged against the property until commercial production commences. After a mine property has been brought into commercial production, costs of any additional work on that property are expensed as incurred, except for large development programs, which will be deferred and depreciated over the remaining life of the related assets.

iii. Depreciation

Depreciation is calculated over the depreciable amount, which is the cost of the asset less its residual value. Assets which are unrelated to production are depreciated according to the straight-line method based on estimated useful lives as follows:

Land	Not depreciated
Buildings	15 - 25 years
Plant and equipment	3 - 15 years
Furniture and fixtures	3 - 10 years
Other	3 - 5 years

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Mining properties and certain mining and conversion assets for which the economic benefits from the asset are consumed in a pattern which is linked to the production level are depreciated according to the unit-of-production method. For conversion assets, the amount of depreciation is measured by the portion of the facilities’ total estimated lifetime production that is produced in that period. For mining assets and properties, the amount of depreciation or depletion is measured by the portion of the mines’ proven and probable mineral reserves recovered during the period. Nuclear generating plants, which are leased assets, are depreciated according to the straight-line method based on the shorter of useful life and remaining lease term.

Depreciation methods, useful lives and residual values are reviewed at each reporting period and are adjusted if appropriate.

iv. Borrowing costs

Borrowing costs on funds directly attributable to finance the acquisition, production or construction of a qualifying asset are capitalized until such time as substantially all the activities necessary to prepare the qualifying asset for its intended use are complete. A qualifying asset is one that takes a substantial period of time to prepare for its intended use. Capitalization is discontinued when the asset enters commercial production or development ceases. Where the funds used to finance a project form part of general borrowings, interest is capitalized based on the weighted average interest rate applicable to the general borrowings outstanding during the period of construction.

v. Repairs and maintenance

The cost of replacing a component of property, plant and equipment is capitalized if it is probable that future economic benefits embodied within the component will flow to the Company. The carrying amount of the replaced component is derecognized. Costs of routine maintenance and repair are charged to products and services sold.

I. Goodwill and intangible assets

Goodwill arising from the acquisition of subsidiaries is initially recognized at cost, measured as the excess of the fair value of the consideration paid over the fair value of the identifiable net assets acquired. At the date of acquisition, goodwill is allocated to the cash generating unit (CGU), or group of CGUs that is expected to receive the economic benefits of the business combination. Goodwill is subsequently measured at cost, less accumulated impairment losses.

Intangible assets acquired individually or as part of a group of assets are initially recognized at cost and measured subsequently at cost less accumulated amortization and impairment losses. Subsequent expenditure is capitalized only when it increases the future economic benefits embodied in the specific asset to which it relates. The cost of a group of intangible assets acquired in a transaction, including those acquired in a business combination that meet the specified criteria for recognition apart from goodwill, is allocated to the individual assets acquired based on their relative fair values.

Intangible assets that have finite useful lives are amortized over their estimated remaining useful lives. Amortization methods and useful lives are reviewed at each reporting period and are adjusted if appropriate.

J. Leased assets

Leases which result in the Company receiving substantially all the risks and rewards of ownership are classified as finance leases. Upon initial recognition, the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments. Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset.

Lease agreements that do not meet the recognition criteria of a finance lease are classified and recognized as operating leases and are not recognized in the Company’s consolidated statements of financial position. Payments made under operating leases are charged to income on a straight-line basis over the lease term. Minimum lease payments made under finance leases are apportioned between finance cost and the reduction of the outstanding liability. The finance cost is allocated to each period of the lease term to produce a constant periodic rate of interest on the remaining balance of the liability.

K. Finance income and finance costs

Finance income comprises interest income on funds invested, gains on the disposal of available-for-sale financial assets, and changes in the fair value of financial assets. Interest income is recognized in earnings as it accrues, using the effective interest method. Finance costs comprise interest and fees on borrowings, unwinding of the discount on provisions and changes in the fair value of financial assets.

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Borrowing costs that are not directly attributable to the acquisition, construction or production of a qualifying asset are expensed in the period incurred.

Foreign currency gains and losses are reported on a net basis as part of finance costs.

L. Research and development costs

Expenditures on research are charged against earnings when incurred. Development costs are recognized as assets when the Company can demonstrate technical feasibility and that the asset will generate probable future economic benefits.

M. Impairment

i. Non-derivative financial assets

Financial assets not classified as at fair value through profit and loss are assessed at each reporting date to determine whether there is objective evidence of impairment. Objective evidence that financial assets (including equity securities) are impaired can include default or delinquency by a debtor, restructuring of an amount due to the Company on terms that the Company would not consider otherwise, indications that a debtor or issuer will enter bankruptcy, or the disappearance of an active market for a security. In addition, for an investment in an equity security, a significant or prolonged decline in its fair value below its cost is objective evidence of impairment.

Impairment losses on available-for-sale financial assets are recognized by transferring the cumulative loss that has been recognized in other comprehensive income, and presented in equity, to earnings. The cumulative loss that is removed from other comprehensive income and recognized in earnings is the difference between the acquisition cost, net of any principal payment and amortization, and the current fair value, less any impairment loss previously recognized in earnings.

If, in a subsequent period, the fair value of an impaired available-for-sale debt security increases and the increase can be related objectively to an event occurring after the impairment loss was recognized in earnings, then the impairment loss is reversed through earnings, otherwise, it is reversed through other comprehensive income. Impairment losses on available-for-sale equity securities that are recognized in earnings are never reversed through earnings.

ii. Non-financial assets

The carrying amounts of Cameco’s non-financial assets are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated. Goodwill is tested annually for impairment.

For impairment testing, assets are grouped together into CGUs which are the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or CGUs. Goodwill arising from a business combination is allocated to CGUs or groups of CGUs that are expected to benefit from the synergies of the combination.

The recoverable amount of an asset or CGU is the greater of its value in use and its fair value less costs to sell. Value in use is based on the estimated future cash flows, discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset or CGU. Fair value is determined as the amount that would be obtained from the sale of the asset or CGU in an arm’s-length transaction between knowledgeable and willing parties. For exploration properties, fair value is based on the implied fair value of the resources in place using comparable market transaction metrics.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its recoverable amount. Impairment losses are recognized in earnings. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the CGU, and then to reduce the carrying amounts of the other assets in the CGU on a pro rata basis.

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Impairment losses recognized in prior periods are assessed at each reporting date whenever events or changes in circumstances indicate that the impairment may have reversed. If the impairment has reversed, the carrying amount of the asset is increased to its recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or amortization, if no impairment loss had been recognized. A reversal of an impairment loss is recognized immediately in earnings. An impairment loss in respect of goodwill is not reversed.

N. Exploration and evaluation expenditures

Exploration and evaluation expenditures are those expenditures incurred by the Company in connection with the exploration for and evaluation of mineral resources before the technical feasibility and commercial viability of extracting a mineral resource are demonstrable. These expenditures include researching and analyzing existing exploration data, conducting geological studies, exploratory drilling and sampling, and compiling prefeasibility and feasibility studies. Exploration and evaluation expenditures are charged against earnings as incurred, except when there is a high degree of confidence in the viability of the project and it is probable that these costs will be recovered through future development and exploitation.

The technical feasibility and commercial viability of extracting a resource is considered to be determinable based on several factors, including the existence of proven and probable reserves and the demonstration that future economic benefits are probable. When an area is determined to be technically feasible and commercially viable, the exploration and evaluation assets attributable to that area are first tested for impairment and then transferred to property, plant and equipment.

Exploration and evaluation costs that have been acquired in a business combination or asset acquisition are capitalized under the scope of IFRS 6, Exploration for and Evaluation of Mineral Resources, and are reported as part of property, plant and equipment.

O. Provisions

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the risk-adjusted expected future cash flows at a pre-tax risk-free rate that reflects current market assessments of the time value of money. The unwinding of the discount is recognized as a finance cost.

i. Environmental restoration

The mining, extraction and processing activities of the Company normally give rise to obligations for site closure and environmental restoration. Closure and restoration can include facility decommissioning and dismantling, removal or treatment of waste materials, as well as site and land restoration. The Company provides for the closure, reclamation and decommissioning of its operating sites in the financial period when the related environmental disturbance occurs, based on the estimated future costs using information available at the reporting date. Costs included in the provision comprise all closure and restoration activity expected to occur gradually over the life of the operation and at the time of closure. Routine operating costs that may impact the ultimate closure and restoration activities, such as waste material handling conducted as a normal part of a mining or production process, are not included in the provision.

The timing of the actual closure and restoration expenditure is dependent upon a number of factors such as the life and nature of the asset, the operating licence conditions and the environment in which the mine operates. Closure and restoration provisions are measured at the expected value of future cash flows, discounted to their present value using a current pre-tax risk-free rate. Significant judgments and estimates are involved in deriving the expectations of future activities and the amount and timing of the associated cash flows.

15

At the time a provision is initially recognized, to the extent that it is probable that future economic benefits associated with the reclamation, decommissioning and restoration expenditure will flow to the Company, the corresponding cost is capitalized as an asset. The capitalized cost of closure and restoration activities is recognized in property, plant and equipment and depreciated on a unit-of-production basis. The value of the provision is gradually increased over time as the effect of discounting unwinds. The unwinding of the discount is an expense recognized in finance costs.

Closure and rehabilitation provisions are also adjusted for changes in estimates. The provision is reviewed at each reporting date for changes to obligations, legislation or discount rates that effect change in cost estimates or life of operations. The cost of the related asset is adjusted for changes in the provision resulting from changes in estimated cash flows or discount rates, and the adjusted cost of the asset is depreciated prospectively.

ii. Waste disposal

The refining, conversion and manufacturing processes generate certain uranium-contaminated waste. The Company has established strict procedures to ensure this waste is disposed of safely. A provision for waste disposal costs in respect of these materials is recognized when they are generated. Costs associated with the disposal, the timing of cash flows and discount rates are estimated both at initial recognition and subsequent measurement.

P. Employee future benefits

i. Pension obligations

The Company accrues its obligations under employee benefit plans. The Company has both defined benefit and defined contribution plans. A defined contribution plan is a pension plan under which the Company pays fixed contributions into a separate entity. The Company has no legal or constructive obligations to pay further contributions if the fund does not hold sufficient assets to pay all employees the benefits relating to employee service in the current and prior periods. A defined benefit plan is a pension plan other than a defined contribution plan. Typically, defined benefit plans define an amount of pension benefit that an employee will receive on retirement, usually dependent on one or more factors such as age, years of service and compensation.

The liability recognized in the consolidated statements of financial position in respect of defined benefit pension plans is the present value of the defined benefit obligation at the reporting date less the fair value of plan assets. The defined benefit obligation is calculated annually, by qualified independent actuaries using the projected unit credit method prorated on service and management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. The present value of the defined benefit obligation is determined by discounting the estimated future cash outflows using interest rates of high-quality corporate bonds that are denominated in the currency in which the benefits will be paid, and that have terms to maturity approximating the terms of the related pension liability.

The Company recognizes all actuarial gains and losses arising from defined benefit plans in other comprehensive income, and reports them in retained earnings. When the benefits of a plan are improved, the portion of the increased benefit relating to past service by employees is recognized immediately in earnings.

For defined contribution plans, the contributions are recognized as employee benefit expense in earnings in the periods during which services are rendered by employees. Prepaid contributions are recognized as an asset to the extent that a cash refund or a reduction in future payments is available.

ii. Other post-retirement benefit plans

The Company provides certain post-retirement health care benefits to its retirees. The entitlement to these benefits is usually conditional on the employee remaining in service up to retirement age and the completion of a minimum service period. The expected costs of these benefits are accrued over the period of employment using the same accounting methodology as used for defined benefit pension plans. Actuarial gains and losses are recognized in other comprehensive income in the period in which they arise. These obligations are valued annually by independent qualified actuaries.

16

iii. Short-term employee benefits

Short-term employee benefit obligations are measured on an undiscounted basis and are expensed as the related service is provided. A liability is recognized for the amount expected to be paid under short-term cash bonus plans if the Company has a present legal or constructive obligation to pay this amount as a result of past service provided by the employee, and the obligation can be measured reliably.

iv. Termination benefits

Termination benefits are payable when employment is terminated by the Company before the normal retirement date, or whenever an employee accepts an entity’s offer of benefits in exchange for termination of employment. Cameco recognizes termination benefits as an expense at the earlier of when the Company can no longer withdraw the offer of those benefits and when the Company recognizes costs for a restructuring. If benefits are payable more than 12 months after the reporting period, they are discounted to their present value.

v. Share-based compensation

For equity-settled plans, the grant date fair value of share-based compensation awards granted to employees is recognized as an employee benefit expense, with a corresponding increase in equity, over the period that the employees unconditionally become entitled to the awards. The amount recognized as an expense is adjusted to reflect the number of awards for which the related service and vesting conditions are expected to be met, such that the amount ultimately recognized as an expense is based on the number of awards that meet the related service and non-market performance conditions at the vesting date.

For cash-settled plans, the fair value of the amount payable to employees is recognized as an expense, with a corresponding increase in liabilities, over the period that the employees unconditionally become entitled to payment. The liability is remeasured at each reporting date and at settlement date. Any changes in the fair value of the liability are recognized as employee benefit expense in earnings.

Cameco’s contributions under the employee share ownership plan are expensed during the year of contribution. Shares purchased with Company contributions and with dividends paid on such shares become unrestricted on January 1 of the second plan year following the date on which such shares were purchased.

Q. Revenue recognition

Cameco supplies uranium concentrates and uranium conversion services to utility customers.

Cameco recognizes revenue on the sale of its nuclear products when the risks and rewards of ownership pass to the customer and collection is reasonably assured. Cameco’s sales are pursuant to an enforceable contract that indicates the type of sales arrangement, pricing and delivery terms, as well as details related to the transfer of title.

Cameco has three types of sales arrangements with its customers in its uranium and fuel services businesses. These arrangements include uranium supply, toll conversion services and conversion supply (converted uranium), which is a combination of uranium supply and toll conversion services.

Uranium supply

In a uranium supply arrangement, Cameco is contractually obligated to provide uranium concentrates to its customers. Cameco-owned uranium is physically delivered to conversion facilities (Converters) where the Converter will credit Cameco’s account for the volume of accepted uranium. Based on delivery terms in a sales contract with its customer, Cameco instructs the Converter to transfer title of a contractually specified quantity of uranium to the customer’s account at the Converter’s facility. At this point, the risks and rewards of ownership have been transferred and Cameco invoices the customer and recognizes revenue for the uranium supply.

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Toll conversion services

In a toll conversion arrangement, Cameco is contractually obligated to convert customer-owned uranium to a chemical state suitable for enrichment. Based on delivery terms in a sales contract with its customer, Cameco either (i) physically delivers converted uranium to enrichment facilities (Enrichers) where it instructs the Enricher to transfer title of a contractually specified quantity of converted uranium to the customer’s account at the Enricher’s facility, or (ii) transfers title of a contractually specified quantity of converted uranium to either an Enricher’s account or the customer’s account. At this point, the risks and rewards of ownership have been transferred and Cameco invoices the customer and recognizes revenue for the toll conversion services.

Conversion supply

In a conversion supply arrangement, Cameco is contractually obligated to provide converted uranium of acceptable origins to its customers. Based on delivery terms in a sales contract with its customer, Cameco either (i) physically delivers converted uranium to the Enricher where it instructs the Enricher to transfer title of a contractually specified quantity of converted uranium to the customer’s account at the Enricher’s facility, or (ii) transfers title of a contractually specified quantity of converted uranium to either an Enricher’s account or a customer’s account at Cameco’s Port Hope conversion facility. At this point, the risks and rewards of ownership have been transferred and Cameco invoices the customer and recognizes revenue for both the uranium supplied and the conversion service provided.

Electricity sales

Electricity sales are recognized at the time of generation, and delivery to the purchasing utility is metered at the point of interconnection with the transmission system. Revenues are recognized on an accrual basis, which includes an estimate of the value of electricity produced during the period but not yet billed.

R. Financial instruments

A financial instrument is any contract that gives rise to a financial asset of one entity and a financial liability or equity instrument of another.

i. Non-derivative financial assets and financial liabilities

At initial recognition, Cameco classifies each of its financial assets and financial liabilities into one of the following categories:

Fair value through profit or loss

A financial asset or liability is classified as at fair value through profit or loss if it is classified as held-for-trading or is designated as such on initial recognition. Cameco classifies a financial instrument as held-for-trading if it was acquired principally for the purpose of selling or repurchasing in the near term, or if it is part of a portfolio with evidence of a recent pattern of short-term profit taking. Directly attributable transaction costs are recognized in earnings as incurred. These financial assets and financial liabilities are measured at fair value, with any gains or losses on revaluation being recognized in earnings.

Held-to-maturity

Held-to-maturity investments are financial assets that an entity has the intention and ability to hold until maturity, provide fixed or determinable payments and contain a fixed maturity date. Assets in this category are initially measured at fair value and subsequently measured at amortized cost using the effective interest method.

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Loans and receivables

Loans and receivables are financial assets that provide fixed or determinable payments and are not quoted in an active market. Assets in this category are initially measured at fair value and subsequently measured at amortized cost using the effective interest method.

Available-for-sale assets

Available-for-sale financial assets are non-derivative financial assets that are either designated in this category or not classified into any of the other categories. These assets are measured at fair value plus any directly attributable transaction costs with any gains or losses on re-measurement recognized in other comprehensive income. Accumulated changes in fair value are recorded as a separate component of equity until the asset is derecognized or impaired, then the cumulative gain or loss in other comprehensive income is transferred to earnings.

Other financial liabilities

This category consists of all non-derivative financial liabilities that do not meet the definition of held-for-trading liabilities, and that have not been designated as liabilities at fair value through profit or loss. These liabilities are initially recognized at fair value less any directly attributable transaction costs and are subsequently measured at amortized cost using the effective interest method.

ii. Derivative financial instruments

The Company holds derivative financial instruments to reduce exposure to fluctuations in foreign currency exchange rates and interest rates. Through its investment in BPLP, the Company also holds commodity instruments to reduce exposure to fluctuations in commodity prices. Except for those designated as hedging instruments, all derivative financial instruments are recorded at fair value in the consolidated statements of financial position, with any directly attributable transaction costs recognized in earnings as incurred. Subsequent to initial recognition, changes in fair value are recognized in earnings.

The purpose of hedging transactions is to modify the Company’s exposure to one or more risks by creating an offset between changes in the fair value of, or the cash inflows attributable to, the hedged item and the hedging item. When hedge accounting is appropriate, the hedging relationship is designated as a fair value hedge, a cash flow hedge, or a foreign currency risk hedge related to a net investment in a foreign operation.

At the inception of a hedging relationship, the Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions. The process includes linking all derivatives to specific assets and liabilities on the consolidated statements of financial position or to specific firm commitments or forecasted transactions. The Company also formally assesses, both at the inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items.

For fair value hedges, changes in the fair value of the derivatives and corresponding changes in fair value of the hedged items attributed to the risk being hedged are recognized in earnings. For cash flow hedges, the effective portion of the changes in the fair values of the derivative instruments are recorded in other comprehensive income until the hedged items are recognized in earnings. Derivative instruments that do not qualify for hedge accounting, or are not designated as hedging instruments, are marked-to-market and the resulting net gains or losses are recognized in earnings.

Separable embedded derivatives

Derivatives may be embedded in other financial instruments (the ’host instrument’). Embedded derivatives are treated as separate derivatives when their economic characteristics and risks are not clearly and closely related to those of the host instrument, the terms of the embedded derivative are the same as those of a stand-alone derivative, and the combined contract is not designated at fair value. These embedded derivatives are measured at fair value with subsequent changes recognized in gains or losses on derivatives.

S. Income tax

Income tax expense is comprised of current and deferred taxes. Current tax and deferred tax are recognized in earnings except to the extent that it relates to a business combination, or items recognized directly in equity or in other comprehensive income.

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Current tax is the expected tax payable or receivable on the taxable income or loss for the year, using tax rates enacted or substantially enacted at the reporting date, and any adjustments to tax payable in respect of previous years.

Deferred tax is recognized in respect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized for unused tax losses, tax credits and deductible temporary differences, to the extent that it is probable that future taxable profits will be available against which they can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

The Company’s exposure to uncertain tax positions is evaluated and a provision is made where it is probable that this exposure will materialize.

T. Share capital

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized as a reduction of equity, net of any tax effects.

U. Earnings per share

The Company presents basic and diluted earnings per share data for its common shares. Earnings per share is calculated by dividing the net earnings attributable to equity holders of the Company by the weighted average number of common shares outstanding.

Diluted earnings per share is determined by adjusting the net earnings attributable to equity holders of the Company and the weighted average number of common shares outstanding, for the effects of all dilutive potential common shares. The calculation of diluted earnings per share assumes that outstanding options which are dilutive to earnings per share are exercised and the proceeds are used to repurchase shares of the Company at the average market price of the shares for the period. The effect is to increase the number of shares used to calculate diluted earnings per share.

V. Segment reporting

An operating segment is a component of the Company that engages in business activities from which it may earn revenues and incur expenses, including revenues and expenses that relate to transactions with any of the Company’s other segments. To be classified as a segment, discrete financial information must be available and operating results must be regularly reviewed by the Company’s Chief Executive Officer.

Segment capital expenditure is the total cost incurred during the period to acquire property, plant and equipment, and intangible assets other than goodwill.

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3. Accounting standards

A. Changes in accounting policy

On January 1, 2013, Cameco adopted the following new standards as issued by the International Accounting Standards Board in accordance with the transitional provisions:

i. Subsidiaries

IFRS 10 Consolidated Financial Statements (IFRS 10) introduces a new control model that is applicable to all investees. Among other things, it requires the consolidation of an investee if the Company controls the investee on the basis of de facto circumstances. In accordance with IFRS 10, Cameco re-assessed the control conclusion for its investees at January 1, 2013. There were no changes to the control conclusion for Cameco’s investees.

ii. Joint arrangements

Under IFRS 11 Joint Arrangements (IFRS 11), Cameco classifies its interests in joint arrangements as either joint operations or joint ventures depending on the structure of the arrangements, the legal form of any separate vehicles, the contractual terms of the arrangements and other facts and circumstances. Previously, the structure of the arrangement was the main determinant of classification.

In accordance with IFRS 11, Cameco has re-evaluated its involvement in joint arrangements at January 1, 2013. As a result, the Company has changed its classification conclusion with respect to its investment in BPLP. BPLP has control over its own assets, liabilities, revenues, and expenses, and because Cameco is entitled to a share of the profits or losses from BPLP’s operations, Cameco has determined that its investment in BPLP should be classified as a joint venture. Accordingly, Cameco applied equity accounting to the investment commencing on January 1, 2013. Previously, the investee was accounted for as a jointly controlled entity using the proportionate consolidation method. Prior period financial statements have been revised to reflect the retrospective adoption of IFRS 11.

iii. Disclosure of interests in other entities

As a result of IFRS 12 Disclosure of Interests in Other Entities, Cameco has expanded its disclosures about its interests in equity-accounted investees (note 12).

iv. Financial assets and financial liabilities

Cameco did not have any new disclosure as a result of adopting IFRS 7 Financial Instruments: Disclosures, as the changes to the standard involved instruments that Cameco does not currently hold.

v. Fair value measurement

IFRS 13 Fair Value Measurement (IFRS 13) establishes a single framework for measuring fair value and making disclosures about fair value measurements when such measurements are required or permitted by other IFRSs. It replaces and expands the disclosure requirements about fair value measurements in other IFRSs, including IFRS 7. As a result, Cameco has included additional disclosures in this regard (see notes 4 and 27).

In accordance with the transitional provisions of IFRS 13, Cameco has applied the new fair value measurement guidelines prospectively and has not provided any comparative information for new disclosures. Notwithstanding the above, the change had no significant impact on the measurements of Cameco’s assets and liabilities.

vi. Employee benefits

Revised IAS 19 Employee Benefits (IAS 19R) has accelerated the recognition of past service costs and replaced interest cost and expected return on plan assets with a measure of net interest on the defined benefit asset or liability. In addition, IAS 19R has resulted in a change in the accounting for both plan administration costs and assets earning no return in refundable tax accounts. These revisions have resulted in adjustments to both Cameco and BPLP’s defined benefit obligation balances as at January 1, 2012 and December 31, 2012. There are also expanded disclosure requirements in IAS 19R.

vii. Presentation of other comprehensive income

As a result of amendments to IAS 1 Presentation of Financial Statements, Cameco has modified the presentation of items of other comprehensive income in its statements of other comprehensive income, to present separately items that may be reclassified to earnings from those that will never be. Comparative information has been revised accordingly.

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The following tables summarize the adjustments made to Cameco’s consolidated statements of earnings for the year ended December 31, 2012 and to its consolidated statements of financial position at January 1, 2012 and December 31, 2012, as a result of retrospectively adopting IFRS 11 and IFRS 19R:

	Year ended
Consolidated statement of earnings	Dec 31/12
Net earnings as previously reported	$	264,583
Adjustments to:
Revenue from products and services		(430,811	)
Cost of products and services sold		171,515
Depreciation and amortization		76,048
Administration		348
Exploration		(91	)
Finance costs		12,695
Gains on derivatives		2,060
Finance income		(6,811	)
Earnings from BPLP		157,846
Share of loss from equity-accounted investees		109
Income tax recovery		4,265
Net earnings as restated	$	251,756
Restated net earnings attributable to:
Equity holders	$	253,309
Non-controlling interest		(1,553	)
	$	251,756

	Year ended
Consolidated statement of comprehensive income	Dec 31/12
Other comprehensive loss as previously reported	$	(106,448	)
Remeasurements of defined benefit liability—equity-accounted investees		12,932
Other comprehensive loss as restated	$	(93,516	)
Restated other comprehensive loss attributable to:
Equity holders	$	(93,396	)
Non-controlling interest		(120	)
	$	(93,516	)

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Consolidated statements of financial position	Dec 31/12			Jan 1/12
Equity as previously reported	$	4,944,267		$	4,923,136
Adjustments to:
Cash and cash equivalents		(325	)		(2,532	)
Accounts receivable		(142,460	)		(95,152	)
Supplies and prepaid expenses		(78,644	)		(67,855	)
Current portion of long-term receivables, investments and other		(23,452	)		(48,345	)
Property, plant and equipment		(433,175	)		(443,063	)
Long-term receivables, investments and other		(100,080	)		(107,195	)
Investments in equity-accounted investees		(6,633	)		3,922
Accounts payable and accrued liabilities		81,123			99,865
Short-term debt		39,500			18,644
Current portion of finance lease obligation		16,337			14,852
Current portion of other liabilities		8,116			17,987
Finance lease obligation		114,676			130,982
Other liabilities		521,911			474,651
Deferred tax liabilities		803			831
Equity as restated	$	4,941,964		$	4,920,728
Restated equity attributable to:
Equity holders	$	4,941,384		$	4,917,185
Non-controlling interest		580			3,543
	$	4,941,964		$	4,920,728

The adjustments to earnings relating to the new and amended standards resulted in a three cent decrease in both basic and diluted earnings per share for the year ended December 31, 2012.

B. New standards and interpretations not yet adopted

A number of new standards, interpretations and amendments to existing standards are not yet effective for the year ended December 31, 2013, and have not been applied in preparing these consolidated financial statements. The following standards, amendments to and interpretations of existing standards have been published and are mandatory for Cameco’s accounting periods beginning on or after January 1, 2014, unless otherwise noted.

i. Financial instruments

In October 2010, the International Accounting Standards Board (IASB) issued IFRS 9, Financial Instruments (IFRS 9). In November 2013, the IASB issued a new general hedge accounting standard, which forms part of IFRS 9. The new standard removes the January 1, 2015 effective date of IFRS 9. The new mandatory effective date will be determined once the classification and measurement and impairment phases of IFRS 9 are finalized.

This standard is part of a wider project to replace IAS 39, Financial Instruments: Recognition and Measurement (IAS 39). IFRS 9 replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The basis of classification depends on the entity’s business model and the contractual cash flow characteristics of the financial asset or liability. It also introduces additional changes relating to financial liabilities and aligns hedge accounting more closely with risk management. The mandatory effective date is not yet determined; however, early adoption of the new standard is still permitted. Cameco does not intend to early adopt IFRS 9 in its financial statements for the annual period beginning January 1, 2014. The extent of the impact of adoption of IFRS 9 has not yet been determined.

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ii. Financial assets and financial liabilities

In December 2011, the IASB issued amendments to IAS 32, Financial Instruments: Presentation (IAS 32). The amendment is effective for periods beginning on or after January 1, 2014 and is to be applied retrospectively. The amendment clarifies matters regarding offsetting financial assets and financial liabilities as well as related disclosure requirements. Cameco intends to adopt the amendments to IAS 32 in its financial statements for the annual period beginning January 1, 2014 and does not expect the amendments to have a material impact on the financial statements.

iii. Levies

In May 2013, the IASB issued International Financial Reporting Interpretations Committee (IFRIC) 21, Levies. IFRIC 21 is effective for annual periods beginning on or after January 1, 2014 and is to be applied retrospectively. IFRIC 21 provides guidance on accounting for levies in accordance with IAS 37, Provisions, Contingent Liabilities and Contingent Assets. The interpretation defines a levy as an outflow from an entity imposed by a government in accordance with legislation and confirms that an entity recognizes a liability for a levy only when the triggering event specified in the legislation occurs. Cameco intends to adopt IFRIC 21 in its financial statements for the annual period beginning January 1, 2014. The extent of the impact of adoption of IFRIC 21 has not yet been determined.

iv. Disclosure of recoverable amounts

In May 2013, the IASB issued amendments to IAS 36 Impairment of Assets (IAS 36). The amendments in IAS 36 are effective for annual periods beginning on or after January 1, 2014 and are to be applied retrospectively. The amendments reverse the unintended requirement in IFRS 13 to disclose the recoverable amount of every cash generating unit to which significant goodwill or indefinite-lived intangible assets have been allocated. Under these amendments, the recoverable amount is required to be disclosed only when an impairment loss has been recognized or reversed. Cameco intends to adopt the amendments to IAS 36 in its financial statements for the annual period beginning January 1, 2014. As the amendments impact certain disclosure requirements only, the Company does not expect the amendments to have a material impact on its financial statements.

4. Determination of fair values

A number of the Company’s accounting policies and disclosures require the measurement of fair value, for both financial and non-financial assets and liabilities.

The fair value of an asset or liability is generally estimated as the amount that would be received on sale of an asset, or paid to transfer a liability in an orderly transaction between market participants at the reporting date. Fair values of assets and liabilities traded in an active market are determined by reference to last quoted prices, in the principal market for the asset or liability. In the absence of an active market for an asset or liability, fair values are determined based on market quotes for assets or liabilities with similar characteristics and risk profiles, or through other valuation techniques. Fair values determined using valuation techniques require the use of inputs, which are obtained from external, readily observable market data when available. In some circumstances, inputs that are not based on observable data must be used. In these cases, the estimated fair values may be adjusted in order to account for valuation uncertainty, or to reflect the assumptions that market participants would use in pricing the asset or liability.

All fair value measurements are categorized into one of three hierarchy levels, described below, for disclosure purposes. Each level is based on the transparency of the inputs used to measure the fair values of assets and liabilities:

Level 1 – Values based on unadjusted quoted prices in active markets that are accessible at the reporting date for identical assets or liabilities.

Level 2 – Values based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.

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Level 3 – Values based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement.

When the inputs used to measure fair value fall within more than one level of the hierarchy, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety.

Transfers between levels of the fair value hierarchy are recognized at the end of the reporting period during which the transfer occurred. There were no transfers between level 1, level 2, or level 3 during the period. Cameco does not have any financial instruments that are categorized as level 3 as of the reporting date.

Further information about the techniques and assumptions used to measure fair values is included in the following notes:

Note 9 – Property, plant and equipment

Note 12 – Equity-accounted investees

Note 25 – Share-based compensation plans

Note 27 – Financial instruments and risk management

5. Use of estimates and judgments

The preparation of the consolidated financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, revenues and expenses. Actual results may differ from these estimates.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future period affected.

Information about critical judgments in applying the accounting policies that have the most significant effect on the amounts recognized in the consolidated financial statements is discussed below. Further details of the nature of these judgments, estimates and assumptions may be found in the relevant notes to the consolidated financial statements.

A. Recoverability of long-lived and intangible assets

Cameco assesses the carrying values of property, plant and equipment, and intangible assets annually or more frequently if warranted by a change in circumstances. If it is determined that carrying values of assets or goodwill cannot be recovered, the unrecoverable amounts are charged against current earnings. Recoverability is dependent upon assumptions and judgments regarding market conditions, costs of production, sustaining capital requirements and mineral reserves. Other assumptions used in the calculation of recoverable amounts are discount rates, future cash flows and profit margins. A material change in assumptions may significantly impact the potential impairment of these assets.

B. Cash generating units

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

C. Provisions for decommissioning and reclamation of assets

Significant decommissioning and reclamation activities are often not undertaken until near the end of the useful lives of the productive assets. Regulatory requirements and alternatives with respect to these activities are subject to change over time. A significant change to either the estimated costs or mineral reserves may result in a material change in the amount charged to earnings.

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D. Deferred income taxes

Cameco operates in a number of tax jurisdictions and is, therefore, required to estimate its income taxes in each of these tax jurisdictions in preparing its consolidated financial statements. In calculating income taxes, consideration is given to factors such as tax rates in the different jurisdictions, non-deductible expenses, valuation allowances, changes in tax law and management’s expectations of future operating results. Cameco estimates deferred income taxes based on temporary differences between the income and losses reported in its consolidated financial statements and its taxable income and losses as determined under the applicable tax laws. The tax effect of these temporary differences is recorded as deferred tax assets or liabilities in the consolidated financial statements. The calculation of income taxes requires the use of judgment and estimates. If these judgments and estimates prove to be inaccurate, future earnings may be materially impacted.

E. Mineral reserves

Depreciation on property, plant and equipment is primarily calculated using the unit-of-production method. This method allocates the cost of an asset to each period based on current period production as a portion of total lifetime production or a portion of estimated mineral reserves. Estimates of life-of-mine and amounts of mineral reserves are updated annually and are subject to judgment and significant change over time. If actual mineral reserves prove to be significantly different than the estimates, there could be a material impact on the amounts of depreciation charged to earnings.

F. Pension, other post-retirement and other post-employment benefits

The carrying value of pensions, other post-retirement and other post-employment benefit obligations is based on actuarial valuations that are sensitive to assumptions concerning discount rates, wage increase rates, and other actuarial assumptions used. Changes in these assumptions could result in a material impact to the consolidated financial statements.

G. Purchase price allocations

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

6. Acquisitions

A. NUKEM Energy GmbH (NUKEM)

On January 9, 2013, Cameco completed the acquisition of NUKEM from Advent International (Advent) and other shareholders, through the purchase of all the outstanding shares for cash consideration of €107,149,000 ($140,494,000 (US)), plus additional consideration of €6,075,000 ($7,808,000 (US)). This additional consideration represents a share of NUKEM’s 2012 earnings under the terms of the agreement. Based on an amending agreement entered into during the year, no further earn-out payments will be made.

While Cameco received the economic benefit of owning NUKEM as of January 1, 2012, the results of NUKEM have been consolidated with the results of Cameco commencing on January 9, 2013. NUKEM is one of the world’s leading traders and brokers of nuclear fuel products and services. The acquisition complements Cameco’s business by strengthening our position in nuclear fuel markets and improving our access to unconventional and secondary sources of supply.

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In accordance with the acquisition method of accounting, the purchase price was allocated to the underlying assets and liabilities assumed based on their fair values at the date of acquisition. Fair values were determined based on discounted cash flows and quoted market prices. The values assigned to the net assets acquired were as follows:

Net assets acquired (USD)
Cash and cash equivalents	$	12,974
Accounts receivable		43,529
Other working capital		5,172
Inventories		165,280
Intangible assets		87,535
Accounts payable and accrued liabilities		(68,464	)
Long-term debt		(116,922	)
Provisions		(15,514	)
Deferred tax liabilities		(53,665	)
Goodwill		88,377
Total	$	148,302
Cash	$	140,494
Additional consideration		7,808
Total	$	148,302

The fair value of the acquired accounts receivable approximates its carrying value due to the short-term nature of the balance. None of the accounts receivable were impaired and the amounts were fully collected.

Intangible assets include the fair value of the purchase and sales contracts that NUKEM was a party to as at January 9, 2013.

The goodwill arising on acquisition is attributable to the difference between the accounting fair value and the tax basis of the net assets acquired, and is not deductible for income tax purposes. Goodwill reflects the value assigned to the expected future earnings capabilities of the organization. This is the earnings potential that we anticipate will be realized through new business arrangements.

Since the effective date of the transaction was January 9, 2013, the consolidated revenue and net earnings for the year is not materially different than what would be reported if the business combination had occurred at the beginning of the year.

Acquisition costs of $3,800,000 have been expensed and included in administration expense in the 2012 consolidated statements of earnings. In addition, an advisory fee of $2,980,000 has been included in administration expense in the consolidated statement of earnings for the year ended December 31, 2013.

As at December 31, 2013, NUKEM had the following commitments (in USD) to purchase uranium and fuel services products:

2014		2015		2016		2017		2018		Thereafter		Total
$	177,186		175,602		245,770		38,420		38,420		153,681	$	829,079

B. Yeelirrie

On December 18, 2012, a wholly owned Cameco subsidiary acquired a 100% interest in the Yeelirrie uranium project in Western Australia from BHP Billiton for a total cost of $453,900,000 (US). Included in the purchase price is $1,500,000 (US) in transaction costs and a $22,000,000 (US) stamp duty payable to the government of Western Australia. Yeelirrie is one of Australia’s largest undeveloped uranium deposits and is located about 650 kilometres northeast of Perth and about 750 kilometres south of Cameco’s Kintyre exploration project. The acquisition was financed by existing cash balances and substantially all of the purchase price was assigned to exploration and evaluation assets included in property, plant and equipment.

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C. Millennium

On June 11, 2012, Cameco acquired a 27.94% interest in the Millennium project from AREVA Resources Canada Inc. (AREVA) for $150,840,000, increasing its ownership to 69.9%. The remaining 30.1% is owned by JCU (Canada) Exploration Co. The Millennium project is a proposed uranium mine located in the Athabasca Basin of northern Saskatchewan. The terms of the purchase agreement provide AREVA with a 4% royalty on revenue from 27.94% of any production that exceeds 63,000,000 pounds U3O8 from this project. The acquisition was financed by existing cash balances and the purchase price was assigned to exploration and evaluation assets included in property, plant and equipment.

7. Accounts receivable

			(Revised - note 3)
	2013		2012
Trade receivables	$	391,749	$	346,668
Receivables due from related parties [note 32]		13,400		33,932
HST/VAT receivables		15,344		14,169
Other receivables		10,882		9,271
Total	$	431,375	$	404,040

The Company’s exposure to credit and currency risks as well as impairment loss related to trade and other receivables, excluding harmonized sales tax (HST)/value added tax (VAT) receivables is disclosed in note 27.

8. Inventories

	2013		2012
Uranium
Concentrate	$	550,305	$	407,067
Broken ore		4,572		22,537
		554,877		429,604
NUKEM		208,217		—
Fuel services		150,221		133,974
Total	$	913,315	$	563,578

Cameco expensed $1,690,000,000 of inventory as cost of sales during 2013 (2012 - $1,159,500,000). Included in cost of sales is a $14,000,000 write-down of NUKEM inventory which Cameco recorded during the year to reflect net realizable value.

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9. Property, plant and equipment

At December 31, 2013

	Land and buildings			Plant and equipment (a)			Furniture and fixtures			Under construction			Exploration and evaluation			Total
Cost
Beginning of year	$	2,722,059		$	1,663,769		$	89,868		$	1,679,571		$	1,126,254		$	7,281,521
Acquisitions [note 6]		—			1,070			—			—			—			1,070
Additions		56,857			18,299			485			528,547			9,131			613,319
Transfers		161,042			141,018			6,929			(308,989	)		—			—
Disposals		(1,467	)		(14,294	)		(578	)		—			(131	)		(16,470	)
Effect of movements in exchange rates		33,403			9,749			516			5,271			(49,390	)		(451	)
End of year		2,971,894			1,819,611			97,220			1,904,400			1,085,864			7,878,989
Accumulated depreciation and impairment
Beginning of year		1,305,639			918,829			71,903			—			168,000			2,464,371
Depreciation charge		169,561			105,101			9,531			—			258			284,451
Transfers		(185	)		692			(507	)		—			—			—
Disposals		(378	)		(9,104	)		(155	)		—			—			(9,637	)
Impairment charge (a)		28			344			—			70,159			7,160			77,691
Effect of movements in exchange rates		17,016			3,667			444			—			(7	)		21,120
End of year		1,491,681			1,019,529			81,216			70,159			175,411			2,837,996
Net book value at December 31, 2013	$	1,480,213		$	800,082		$	16,004		$	1,834,241		$	910,453		$	5,040,993

At December 31, 2012

																(Revised - note 3)
	Land and buildings			Plant and equipment (a)			Furniture and fixtures			Under construction			Exploration and evaluation			Total
Cost
Beginning of year	$	2,518,918		$	1,471,739		$	78,981		$	1,419,464		$	513,664		$	6,002,766
Acquisitions [note 6]		—			—			—			—			598,407			598,407
Additions		97,481			21,215			1,271			577,743			19,416			717,126
Transfers		117,648			187,105			9,800			(314,553	)		—			—
Disposals		(2,281	)		(13,180	)		(3	)		—			—			(15,464	)
Effect of movements in exchange rates		(9,707	)		(3,110	)		(181	)		(3,083	)		(5,233	)		(21,314	)
End of year		2,722,059			1,663,769			89,868			1,679,571			1,126,254			7,281,521
Accumulated depreciation and impairment
Beginning of year		1,179,652			852,217			63,242			—			—			2,095,111
Depreciation charge		131,207			80,107			8,785			—			—			220,099
Disposals		(1,251	)		(12,554	)		(4	)		—			—			(13,809	)
Impairment charge (b)		—			—			—			—			168,000			168,000
Effect of movements in exchange rates		(3,969	)		(941	)		(120	)		—			—			(5,030	)
End of year		1,305,639			918,829			71,903			—			168,000			2,464,371
Net book value at December 31, 2012	$	1,416,420		$	744,940		$	17,965		$	1,679,571		$	958,254		$	4,817,150

29

(a) During 2013, Cameco recognized a $70,159,000 impairment charge relating to its agreement with Talvivaara Mining Company Plc. to purchase uranium produced at the Sotkamo nickel-zinc mine in Finland. The impairment charge represents the full amount of Cameco’s investment which was used to cover construction costs with the amount to be repaid through deliveries of uranium concentrate. The amount of the charge was determined as the excess of the carrying value over the fair value less costs to sell. Due to Talvivaara’s weak financial position and application to the Finnish government to undergo a corporate restructuring, as an unsecured creditor Cameco determined the fair value less costs to sell to be nil and as such recognized an impairment charge for the full amount of the asset.

(b) In 2012, Cameco recognized a $168,000,000 impairment charge relating to Kintyre, its advanced uranium exploration project in Australia. Due to the weakening of the uranium market since the asset was purchased in 2008, no increase to the mineral resource estimate in 2012 and the decision not to proceed with the detailed feasibility study, the Company concluded it was appropriate to recognize an impairment charge. The amount of the charge was determined as the excess of the carrying value over the fair value less costs to sell based on the implied fair value of the resources in place using comparable market transaction metrics.

10. Goodwill and intangible assets

A. Reconciliation of carrying amount

	Goodwill		Contracts		Intellectual property		Patents		Total
Cost
Beginning of year	$	—	$	—	$	118,819	$	8,697	$	127,516
Additions [note 6]		87,460		86,627		—		—		174,087
Effect of movements in exchange rates		6,538		6,475		—		601		13,614
End of year		93,998		93,102		118,819		9,298		315,217
Accumulated amortization
Beginning of year		—		—		33,694		721		34,415
Amortization charge		—		79,609		3,246		494		83,349
Effect of movements in exchange rates		—		3,351		—		71		3,422
End of year		—		82,960		36,940		1,286		121,186
Net book value at December 31, 2013	$	93,998	$	10,142	$	81,879	$	8,012	$	194,031

	Intellectual property		Patents			Total
Cost
Beginning of year	$	118,819	$	8,890		$	127,709
Effect of movements in exchange rates		—		(193	)		(193	)
End of year		118,819		8,697			127,516
Accumulated amortization
Beginning of year		29,735		246			29,981
Amortization charge		3,959		484			4,443
Effect of movements in exchange rates		—		(9	)		(9	)
End of year		33,694		721			34,415
Net book value at December 31, 2012	$	85,125	$	7,976		$	93,101

30

B. Amortization

The intangible asset values relate to intellectual property acquired with Cameco Fuel Manufacturing (CFM), patents acquired with UFP Investments LLC (UFP) and purchase and sale contracts acquired with NUKEM. The CFM intellectual property is being amortized on a unit-of-production basis over its remaining life. Amortization is allocated to the cost of inventory and is recognized in cost of products and services sold as inventory is sold. The patents acquired with UFP are being amortized to cost of products and services sold on a straight-line basis over their remaining life which expires in July 2029. The NUKEM purchase and sale contracts will be amortized to earnings over the remaining terms of the underlying contracts, which extend to 2022. Amortization of the purchase contracts is allocated to the cost of inventory and is included in cost of sales as inventory is sold. Sale contracts are amortized to revenue. The approximate amount of pre-tax earnings (in USD) relating to the amortization of the fair value allocated to the NUKEM contracts is as follows:

2014			2015		2016		2017		2018		2019		2020		2021		2022		Total
$	(694	)		1,933		2,897		994		1,091		975		871		777		692	$	9,536

C. Impairment test

For the purpose of impairment testing, goodwill is attributable to NUKEM, which is considered a CGU.

The recoverable amount of NUKEM was estimated based on a value in use calculation, which involved discounting the future cash flows expected to be generated from the continuing use of the CGU. The estimated recoverable amount of NUKEM exceeded its carrying amount by approximately $70,500,000 (US) and therefore no impairment loss was recognized.

Five years of cash flows were included in the discounted cash flow model. Any cash flows expected to be generated beyond the initial five-year period were extrapolated using a terminal value growth rate. The projected cash flows included in the calculation were based upon NUKEM’s approved financial forecasts and strategic plan, which incorporate NUKEM’s current contract portfolio as well as management’s expectations regarding future business activity. The key assumptions used in the estimation of the value in use were as follows:

	2013
Discount rate (pre-tax)		11.6	%
Discount rate (post-tax)		8.8	%
Terminal value growth rate		2.5	%

The discount rate was determined based on NUKEM’s internal weighted average cost of capital, adjusted for the marginal return a market participant would expect to earn on an investment in the entity. It represents a nominal, post-tax figure. The terminal value growth rate was determined based on management’s expected average annual long-term growth in the uranium industry. The rate represents a nominal figure, and it is consistent with forecast economic growth rates observed in the market.

Other key assumptions include uranium price forecasts and perpetual cash flows. Uranium prices applied in the calculation were based on approved internal price forecasts, which reflect management’s experience and industry expertise. These prices are consistent with expected long-term prices observed in the market. Perpetual cash flows have been determined based on management’s expectation of future business activity.

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Cameco has validated the results of the value in use calculation by performing sensitivity tests on its key assumptions. Holding all other variable constant, the decreases in recoverable amount created by marginal changes in each of the key assumptions are as follows:

	Change in assumption	Amount of decrease
Discount rate	1% increase	$	19,344
Terminal value growth rate	1% decrease		12,847
Uranium prices	$1/lb decrease		4,220
Perpetual annual cash flow	$1 Million (US) decrease		11,331

As a result of these tests, the Company believes that any reasonably possible changes in the key assumptions would not result in NUKEM’s carrying amount exceeding its recoverable amount.

11. Long-term receivables, investments and other

				(Revised - note 3)
	2013			2012
Investments in equity securities	$	22,805		$	20,599
Derivatives [note 27]		7,391			22,453
Advances receivable from JV Inkai LLP [note 32]		95,319			87,264
Investment tax credits		82,177			69,690
Amounts receivable related to tax dispute [note 22]		59,475			13,400
Other		24,156			20,759
		291,323			234,165
Less current portion		(3,775	)		(22,807	)
Net	$	287,548		$	211,358

12. Equity-accounted investees

			(Revised - note 3)
	2013		2012
Interest in BPLP [note 16]	$	294,537	$	—
Interest in GLE		185,162		185,698
Interests in other associates		7,104		16,793
Interests in other joint ventures		5,909		3,398
	$	492,712	$	205,889

A. Joint ventures

i. Interest in BPLP (note 33)

BPLP operates four nuclear reactors at the Bruce B electricity-generating station in southern Ontario. Cameco holds a 31.6% interest in the BPLP partnership, which is governed by an agreement that provides for joint control of the strategic operating, investing and financing activities among the three major partners. BPLP is a joint venture and Cameco accounts for it under the equity method of accounting.

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The following table summarizes the financial information of BPLP (100%):

	2013			2012
Cash and cash equivalents	$	22,700		$	1,500
Other current assets		686,700			821,700
Non-current assets		1,537,800			1,557,700
Current liabilities		(391,200	)		(493,000	)
Non-current liabilities		(1,029,500	)		(2,141,000	)
Net assets (liabilities)	$	826,500		$	(253,100	)
	2013			2012
Revenue from products and services	$	1,369,800		$	1,487,400
Cost of products and services sold		(776,500	)		(724,200	)
Depreciation and amortization		(223,800	)		(220,500	)
Finance income		18,800			20,400
Finance costs		(27,000	)		(46,800	)
Earnings before income taxes	$	361,300		$	516,300
Cameco’s share		114,171			163,151
Adjustments (i)		(4,618	)		(5,305	)
Cameco’s share of earnings before taxes	$	109,553		$	157,846

(i) In addition to its proportionate share of earnings from BPLP, Cameco records certain consolidating adjustments to amortize fair values assigned to assets and liabilities at the time of acquisition.

The following table reconciles the summarized financial information to the carrying amount of Cameco’s interest in BPLP:

	2013			2012
Cameco’s share of net assets	$	261,174		$	(79,980	)
Proprietary assets and other adjustments		33,363			39,447
Carrying amount in the statement of financial position	$	294,537		$	(40,533	)
Beginning of the year	$	(40,533	)	$	10,600
Share of earnings		114,171			163,151
Share of comprehensive income (loss)		314,831			(93,694	)
Net distributions received		(91,166	)		(114,392	)
Proprietary adjustments		(2,766	)		(6,198	)
Carrying amount in the statement of financial position	$	294,537		$	(40,533	)

(a) During the year, Cameco, Cameco Bruce Holdings II Inc., BPC Generation Infrastructure Trust (BPC) and TransCanada Pipelines Limited (TransCanada) (collectively, the Consortium), signed an agreement with BE confirming the amount of the damages paid to the Consortium in connection with the claim against British Energy Limited and British Energy International Holdings Limited (collectively, BE) on the issues of repair costs and lost revenue for breach of a representation and warranty contained in the February 14, 2003 Amended and Restated Master Purchase Agreement under which the Consortium acquired BE’s interest in BPLP.

In connection with this arbitration, BE had issued on February 10, 2006 and then served on OPG and BPLP a Statement of Claim. This Statement of Claim seeks damages for any amounts that BE is found liable to pay to the Consortium in connection with the Unit 8 steam generator arbitration described above, additional damages in the amount of $500,000,000, costs pre and post judgement interest amongst other things. As part of the settlement noted above, BE is effectively discontinuing their action against BPLP.

33

(b) Annual supplemental rents of $31,000,000 (subject to CPI) per operating reactor are payable by BPLP to OPG. Should the hourly annual average price of electricity in Ontario fall below $30 per megawatt hour for any calendar year, the supplemental rent reduces to $12,000,000 per operating reactor. In accordance with the Sublease Agreement, BALP will participate in its share of any adjustments to the supplemental rent. During 2013, BPLP recognized an amount receivable of $79,000,000 and a related reduction to lease expense, with Cameco’s share being $25,000,000.

(c) Cameco, TransCanada and BPC have assumed the obligations to provide financial guarantees on behalf of BPLP. Cameco has provided the financial assurance of termination payments to OPG pursuant to the lease agreement of $58,300,000 with a term to 2018. The fair value of this guarantee is nominal.

(d) Under a supply contract with the Ontario Power Authority (OPA), BPLP is entitled to receive payments from the OPA during periods when the market price for electricity in Ontario is lower than the floor price defined under the agreement during a calendar year. On July 6, 2009, BPLP and the OPA amended the supply contract such that beginning in 2009, the annual payments received will not be subject to repayment in future years. Previously, the payments received under the agreement were subject to repayment during the entire term of the contract, dependent on the spot price in future periods. On April 3, 2013, BPLP and the OPA reached an agreement to amend the supply contract to extend the floor price from the original end of life dates from between 2016 and 2019 to between 2019 and 2020. During 2013, BPLP recorded as revenue $698,300,000 (2012 - $773,300,000) under this agreement, with Cameco’s share being $220,700,000 (2012 - $244,400,000).

ii. Other joint ventures

Cameco has a number of individually immaterial joint ventures. The following table summarizes, in aggregate, the carrying amount and share of earnings and other comprehensive income of these joint ventures:

	2013		2012
Carrying amount of joint ventures	$	5,909	$	3,398
Share of earnings from operations and comprehensive income	$	3,241	$	388

B. Associates

i. GE-Hitachi Global Laser Enrichment LLC (GLE)

GLE primarily operates in North Carolina and is testing a third-generation technology that, if successful, will use lasers to commercially enrich uranium. Cameco owns a 24% interest in GLE and accounts for it under the equity method of accounting.

34

The following table summarizes the financial information of GLE:

	2013			2012
Current assets	$	526		$	492
Non-current assets		206,107			244,330
Current liabilities		(5,280	)		(4,939	)
Net assets (100%)	$	201,353		$	239,883
Cameco’s share of net assets (24%)	$	48,325		$	57,572
Proprietary assets and other adjustments		136,837			128,126
Carrying amount in the statement of financial position	$	185,162		$	185,698
Loss from operations and comprehensive loss	$	(54,477	)	$	(12,724	)
Cameco’s share of loss from operations and comprehensive loss (24%)	$	(13,074	)	$	(3,054	)

A promissory note was issued to finance the acquisition of GLE. The promissory note is payable on demand and bears interest at market rates (note 32).

ii. Other associates

Cameco has a number of individually immaterial associates. The following table summarizes, in aggregate, the carrying amount and share of loss and other comprehensive income of these associates:

	2013			2012
Carrying amount of associates	$	7,104		$	16,793
Share of loss from operations and comprehensive loss	$	(1,034	)	$	(3,230	)

At December 31, 2013, the quoted value of the Company’s share in associates having shares listed on recognized stock exchanges was $19,758,000 (2012 - $29,512,000). The carrying value of these investments were $7,104,000 at December 31, 2013 (2012 - $7,745,000).

13. Accounts payable and accrued liabilities

			(Revised - note 3)
	2013		2012
Trade payables	$	346,390	$	275,571
Non-trade payables		72,857		100,723
Payables due to related parties		18,694		11,359
Total	$	437,941	$	387,653

The Company’s exposure to currency and liquidity risk related to trade and other payables is disclosed in note 27.

14. Short-term debt

			(Revised - note 3)
	2013		2012
Promissory note payable	$	10,601	$	42,106
Commercial paper		24,974		24,984
NUKEM short-term loans		14,655		—
Total	$	50,230	$	67,090

35

In 2008, a promissory note in the amount of $73,344,000 (US) was issued to finance the acquisition of GLE. The promissory note is payable on demand and bears interest at a market rate of 0.95%. At December 31, 2013, $9,967,000 (US) was outstanding under this promissory note (2012—$42,322,000 (US)).

Cameco borrows directly in the commercial paper market. As of December 31, 2013, there was $24,974,000 outstanding (2012—$24,984,000), bearing interest at an average rate of 1.13%.

JV Inkai LLP (Inkai) has a $20,000,000 (US) revolving credit facility that is available until August 11, 2015. Cameco’s share of this facility is $12,000,000 (US). No balance was outstanding under this facility at December 31, 2013, or December 31, 2012.

During 2013, NUKEM entered into a multicurrency revolving loan facility that is available until February 15, 2018. Total funds of €100,000,000 are available under the facility, which can be drawn in either Euros or US dollars in the form of bank overdrafts, letters of credit, short-term loans, or foreign exchange facilities. Any amounts drawn in Euros bear interest at a rate equal to the comparable EURIBOR on the draw date plus 0.9%, while amounts drawn in US dollars bear interest at a rate equal to the comparable LIBOR on the draw date plus 1.3%.

As of December 31, 2013, NUKEM had drawn a total of €38,130,000 against the facility, of which €28,130,000 was drawn in the form of bank overdrafts, and €10,000,000 in the form of short-term loans. The bank overdrafts are due on demand and carry a variable interest rate, while the short-term loans are due on January 23, 2014 and bear interest at a rate of 1.14% per annum. NUKEM also has $693,000 (US) in letters of credit drawn on the facility in support of performance obligations under outstanding delivery contracts.

The terms of the facility contain a financial covenant that requires NUKEM to maintain a minimum working capital to debt ratio of 1.35. The facility also stipulates Cameco as a guarantor for NUKEM’s withdrawals, and requires the Company to maintain a credit rating of at least BBB-. Failure to comply with these covenants could result in cancellation of the facility and accelerated payment of any outstanding amounts. As of December 31, 2013, NUKEM and Cameco were in compliance with the covenants, and the Company does not expect its operating and investing activities in 2014 to be constrained by them.

15. Long-term debt

	2013		2012
Unsecured debentures
Series C - 4.70% debentures due September 16, 2015	$	299,537	$	299,265
Series D - 5.67% debentures due September 2, 2019		497,003		496,566
Series E - 3.75% debentures due November 14, 2022		397,626		397,403
Series F - 5.09% debentures due November 14, 2042		99,217		99,206
Total	$	1,293,383	$	1,292,440

Cameco has a $1,250,000,000 unsecured revolving credit facility that is available until November 1, 2018. Upon mutual agreement, the facility can be extended for an additional year on the anniversary date. In addition to direct borrowings under the facility, up to $100,000,000 can be used for the issuance of letters of credit and, to the extent necessary, it may be used to provide liquidity support for the Company’s commercial paper program. The agreement also provides the ability to increase the revolving credit facility above $1,250,000,000 by increments no less than $50,000,000, to a total of $1,750,000,000. The facility ranks equally with all of Cameco’s other senior debt. As of December 31, 2013, there were no amounts outstanding under this facility.

Cameco has $798,774,000 ($443,699,000 and $333,844,000 (US)) in letter of credit facilities. Outstanding letters of credit at December 31, 2013 amounted to $790,944,000 ($436,957,000 and $331,712,000 (US)) (2012—$672,224,000 ($405,421,000 and $267,879,000 (US))), the majority of which relate to future decommissioning and reclamation liabilities [note 17].

36

Cameco is bound by a covenant in its revolving credit facility. The covenant requires a funded debt to tangible net worth ratio equal to or less than 1:1. Non-compliance with this covenant could result in accelerated payment and termination of the revolving credit facility. At December 31, 2013, Cameco was in compliance with the covenant and does not expect its operating and investing activities in 2014 to be constrained by it.

The table below represents currently scheduled maturities of long-term debt:

2014		2015		2016		2017		2018		Thereafter		Total
$	—		299,537		—		—		—		993,846	$	1,293,383

16. Other liabilities

				(Revised - note 3)
	2013			2012
Deferred sales	$	55,126		$	9,820
Derivatives [note 27]		30,923			1,954
Accrued pension and post-retirement benefit liability [note 26]		45,931			32,647
Interest in BPLP [note 12]		—			40,533
Other		8,085			5,591
		140,065			90,545
Less current portion		(60,685	)		(13,028	)
Net	$	79,380		$	77,517

17. Provisions

	Reclamation			Waste disposal			Total
Beginning of year	$	552,636		$	16,818		$	569,454
Changes in estimates and discount rates		1,958			397			2,355
Provisions used during the period		(9,576	)		(474	)		(10,050	)
Unwinding of discount		16,161			230			16,391
Impact of foreign exchange		12,763			—			12,763
End of year	$	573,942		$	16,971		$	590,913
Current	$	17,817		$	2,396		$	20,213
Non-current		556,125			14,575			570,700
	$	573,942		$	16,971		$	590,913

A. Reclamation provision

Cameco’s estimates of future decommissioning obligations are based on reclamation standards that satisfy regulatory requirements. Elements of uncertainty in estimating these amounts include potential changes in regulatory requirements, decommissioning and reclamation alternatives and amounts to be recovered from other parties.

Cameco estimates total future decommissioning and reclamation costs for its existing operating assets to be $823,493,000. The expected timing of these outflows is based on life-of-mine plans with the majority of expenditures expected to occur after 2019. These estimates are reviewed by Cameco technical personnel as required by regulatory agencies or more frequently as circumstances warrant. In connection with future decommissioning and reclamation costs, Cameco has provided financial assurances of $767,635,000 in the form of letters of credit to satisfy current regulatory requirements.

37

The reclamation provision relates to the following segments:

	2013		2012
Uranium	$	468,546	$	435,842
Fuel Services		105,396		116,794
Total	$	573,942	$	552,636

B. Waste disposal

The Fuel Services division consists of the Blind River refinery, Port Hope conversion facility and Cameco fuel manufacturing. The refining, conversion and manufacturing processes generate certain uranium contaminated waste. These include contaminated combustible material (paper, rags, gloves, etc.), and contaminated non-combustible material (metal parts, soil from excavations, building and roofing materials, spent uranium concentrate drums, etc.). These materials can in some instances be recycled or reprocessed. A provision for waste disposal costs in respect of these materials is recognized when they are generated.

Cameco estimates total future costs related to existing waste disposal to be $18,250,000. These outflows are expected to occur within the next eight years.

18. Share capital

Authorized share capital:

• Unlimited number of first preferred shares

• Unlimited number of second preferred shares

• Unlimited number of voting common shares, no stated par value, and

• One Class B share

A. Common shares

Number issued (number of shares)	2013		2012
Beginning of year		395,350,394		394,745,423
Issued:
Stock option plan [note 25]		126,836		604,971
Total		395,477,230		395,350,394

All issued shares are fully paid.

B. Class B share

One Class B share issued during 1988 and assigned $1 of share capital entitles the shareholder to vote separately as a class in respect of any proposal to locate the head office of Cameco to a place not in the province of Saskatchewan.

C. Dividends

Dividends on Cameco Corporation common shares are declared in Canadian dollars. For the year ended December 31, 2013, the dividend declared per share was $0.40 (December 31, 2012—$0.40).

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19. Employee benefit expense

The following employee benefit expenses are included in cost of products and services sold, administration, exploration, research and development, other income, and property, plant and equipment:

			(Revised - note 3)
	2013		2012
Wages and salaries	$	353,772	$	347,615
Statutory and company benefits		62,287		61,884
Equity-settled share-based compensation [note 25]		24,289		22,780
Expenses related to defined benefit plans [note 26]		4,103		4,172
Contributions to defined contribution plans [note 26]		16,441		16,114
Cash-settled share-based compensation [note 25]		1,272		677
Total	$	462,164	$	453,242

20. Finance costs

				(Revised - note 3)
	2013			2012
Interest on long-term debt	$	66,273		$	46,674
Unwinding of discount on provisions		16,391			13,537
Other charges		6,286			5,839
Foreign exchange losses (gains)		(27,378	)		587
Interest on short-term debt		549			1,017
Total	$	62,121		$	67,654

No borrowing costs were determined to be eligible for capitalization during the year.

21. Other expense

	2013			2012
Loss on sale of investments	$	(14,952	)	$	—
Contract termination fee		—			(30,294	)
Claim settlement		(1,037	)		11,000
Other		(2,337	)		(5,452	)
Total	$	(18,326	)	$	(24,746	)

39

22. Income taxes

A. Significant components of deferred tax assets and liabilities

				(Revised - note 3)					(Revised - note 3)
	Recognized in earnings						As at December 31
	2013			2012			2013		2012
Assets
Inventories	$	(3,250	)	$	3,250		$	—	$	3,250
Provision for reclamation		9,084			7,152			174,708		166,588
Foreign exploration and development		(2,711	)		(62	)		6,910		9,621
Income tax losses		73,412			59,174			199,412		126,241
Defined benefit plan actuarial losses		—			—			8,807		89,495
Other		8,672			15,807			59,628		47,691
Deferred tax assets		85,207			85,321			449,465		442,886
Liabilities
Property, plant and equipment		(42,994	)		(16,645	)		184,930		226,723
Inventories		(15,825	)		(4,629	)		37,139		—
Long-term investments and other		(24,918	)		15,204			3,102		28,020
Deferred tax liabilities		(83,737	)		(6,070	)		225,171		254,743
Net deferred tax asset	$	168,944		$	91,391		$	224,294	$	188,143

				(Revised - note 3)
Deferred tax allocated as	2013			2012
Deferred tax assets	$	266,203		$	193,916
Deferred tax liabilities		(41,909	)		(5,773	)
Net deferred tax asset	$	224,294		$	188,143

Based on projections of future income, realization of these deferred tax assets is probable and consequently a deferred tax asset has been recorded.

B. Movement in net deferred tax assets and liabilities

				(Revised - note 3)
	2013			2012
Net deferred tax asset at beginning of year	$	188,143		$	74,058
Deferred tax liability on acquisition of NUKEM		(52,964	)		—
Recovery for the year in net earnings		168,944			91,391
Recovery (expense) for the year in other comprehensive income		(79,427	)		23,334
Foreign exchange adjustments		(402	)		(640	)
End of year	$	224,294		$	188,143

C. Significant components of unrecognized deferred tax assets

	2013		2012
Income tax losses	$	72,656	$	73,019
Property, plant and equipment		54,759		58,249
Long-term investments and other		12,539		7,750
Total	$	139,954	$	139,018

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D. Tax rate reconciliation

The provision for income taxes differs from the amount computed by applying the combined expected federal and provincial income tax rate to earnings before income taxes. The reasons for these differences are as follows:

`				(Revised - note 3)
	2013			2012
Earnings before income taxes and non-controlling interest	$	227,929		$	201,115
Combined federal and provincial tax rate		26.9	%		26.9	%
Computed income tax expense		61,313			54,100
Increase (decrease) in taxes resulting from:
Difference between Canadian rates and rates applicable to subsidiaries in other countries		(200,877	)		(173,497	)
Change in unrecognized deferred tax assets		11,297			52,742
Other taxes		3,332			3,524
Share-based compensation plans		3,580			3,828
Change in tax provision related to transfer pricing		10,000			9,000
Non-deductible capital amounts		18,328			—
Other permanent differences		3,269			(338	)
Income tax recovery	$	(89,758	)	$	(50,641	)

E. Reassessments

In 2008, as part of the ongoing annual audits of Cameco’s Canadian tax returns, Canada Revenue Agency (CRA) disputed the transfer pricing structure and methodology used by Cameco and its wholly owned Swiss subsidiary, Cameco Europe Ltd. (CEL), in respect of sale and purchase agreements for uranium products. From December 2008 to date, CRA issued notices of reassessment for the taxation years 2003 through 2008, which have increased Cameco’s income for Canadian tax purposes by approximately $43,000,000, $108,000,000, $197,000,000, $243,000,000, $708,000,000 and $744,000,000, respectively. Cameco believes it is likely that CRA will reassess Cameco’s tax returns for subsequent years on a similar basis and that these will result in future cash payments on receipt of the reassessments.

Using the methodology we believe that CRA will continue to apply, and including the $2,043,000,000 already reassessed, we expect to receive notices of reassessment for a total of approximately $5,700,000,000 for the years 2003 through 2013, which would increase Cameco’s income for Canadian tax purposes and result in a related tax expense of approximately $1,600,000,000. In addition to penalties already imposed, CRA may continue to apply penalties to taxation years subsequent to 2007. As a result, we estimate that cash taxes and transfer pricing penalties would be between $1,250,000,000 and $1,300,000,000. 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, or between $625,000,000 and $650,000,000, plus related interest and instalment penalties assessed, which would be material to Cameco.

Under 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. In light of our view of the likely outcome of the case, we expect to recover the amounts remitted to CRA, including the $59,475,000 already paid as at December 31, 2013 (2012—$13,400,000) (note 11). Included in this receivable is $36,000,000 that relates to a $72,000,000 transfer pricing penalty that CRA’s Transfer Pricing Review Committee has imposed 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. In addition, the 2008 reassessment has resulted in Cameco being required to make a cash payment of approximately $44,000,000 in the first quarter of 2014.

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.

41

Having regard to advice from its external advisors, Cameco’s opinion is that CRA’s position is incorrect, and Cameco is contesting CRA’s position and expects to recover any cash paid as a result of the reassessments. However, to reflect the uncertainties of CRA’s appeals process and litigation, Cameco has recorded a cumulative tax provision related to this matter for the years 2003 through 2013 in the amount of $73,000,000. While the resolution of this matter may result in liabilities that are higher or lower than the reserve, management believes that the ultimate resolution will not be material to Cameco’s financial position, results of operations or liquidity in the year(s) of resolution. Resolution of this matter as stipulated by CRA would be material to Cameco’s financial position, results of operations or liquidity in the year(s) of resolution, and other unfavourable outcomes for the years 2003 through 2013 could be material to Cameco’s financial position, results of operations and cash flows in the year(s) of resolution.

Further to Cameco’s decision to contest CRA’s reassessments, Cameco is pursuing its appeal rights under Canadian federal and provincial tax legislation.

F. Earnings and income taxes by jurisdiction

				(Revised - note 3)
	2013			2012
Earnings (loss) before income taxes
Canada	$	(602,568	)	$	(336,957	)
Foreign		830,497			538,072
	$	227,929		$	201,115
Current income taxes
Canada	$	13,673		$	504
Foreign		65,513			40,246
	$	79,186		$	40,750
Deferred income tax recovery
Canada	$	(133,588	)	$	(79,315	)
Foreign		(35,356	)		(12,076	)
	$	(168,944	)	$	(91,391	)
Income tax recovery	$	(89,758	)	$	(50,641	)

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G. Income tax losses

At December 31, 2013, income tax losses carried forward of $968,347,000 (2012—$702,654,000) are available to reduce taxable income. These losses expire as follows:

Date of expiry	Canada		US		Other		Total
2019	$	—	$	—	$	1,680	$	1,680
2020		—		—		1,998		1,998
2029		—		21,856		—		21,856
2030		46		1,277		—		1,323
2031		140,593		18,641		—		159,234
2032		218,823		18,396		—		237,219
2033		280,694		23,448		—		304,142
No expiry		—		—		240,895		240,895
	$	640,156	$	83,618	$	244,573	$	968,347

Included in the table above is $244,845,000 (2012—$243,080,000) of temporary differences related to loss carry forwards where no future benefit is realized.

H. Other comprehensive loss

Other comprehensive loss included on the consolidated statements of comprehensive income and the consolidated statements of changes in equity is presented net of income taxes. The following income tax amounts are included in each component of other comprehensive loss:

For the year ended December 31, 2013

	Before tax			Income tax recovery (expense)			Net of tax
Remeasurements of defined benefit liability	$	2,585		$	(715	)	$	1,870
Remeasurements of defined benefit liability—equity-accounted investees		319,887			(79,972	)		239,915
Exchange differences on translation of foreign operations		(10,792	)		—			(10,792	)
Gains on derivatives designated as cash flow hedges—equity-accounted investees		253			(63	)		190
Gains on derivatives designated as cash flow hedges transferred to net earnings—equity-accounted investees		(5,309	)		1,327			(3,982	)
Unrealized gains on available-for-sale assets		32			(4	)		28
	$	306,656		$	(79,427	)	$	227,229

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For the year ended December 31, 2012 (revised – note 3)

	Before tax			Income tax recovery (expense)			Net of tax
Remeasurements of defined benefit liability	$	294		$	(113	)	$	181
Remeasurements of defined benefit liability—equity-accounted investees		(73,059	)		18,265			(54,794	)
Exchange differences on translation of foreign operations		(23,287	)		—			(23,287	)
Gains on derivatives designated as cash flow hedges —equity-accounted investees		5,309			(1,327	)		3,982
Gains on derivatives designated as cash flow hedges transferred to net earnings—equity-accounted investees		(25,934	)		6,484			(19,450	)
Unrealized losses on available-for-sale assets		(24	)		5			(19	)
Gains on available-for-sale assets transferred to net earnings		(149	)		20			(129	)
	$	(116,850	)	$	23,334		$	(93,516	)

23. Per share amounts

Per share amounts have been calculated based on the weighted average number of common shares outstanding during the period. The weighted average number of paid shares outstanding in 2013 was 395,427,548 (2012—395,234,091).

			(Revised - note 3)
	2013		2012
Basic earnings per share computation
Net earnings attributable to equity holders	$	318,495	$	253,309
Weighted average common shares outstanding		395,428		395,234
Basic earnings per common share	$	0.81	$	0.64
Diluted earnings per share computation
Net earnings attributable to equity holders	$	318,495	$	253,309
Weighted average common shares outstanding		395,428		395,234
Dilutive effect of stock options		126		605
Weighted average common shares outstanding, assuming dilution		395,554		395,839
Diluted earnings per common share	$	0.81	$	0.64

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24. Statements of cash flows

				(Revised - note 3)
	2013			2012
Changes in non-cash working capital:
Accounts receivable	$	26,972		$	113,195
Inventories		(107,221	)		(56,708	)
Supplies and prepaid expenses		(60,738	)		3,094
Accounts payable and accrued liabilities		(21,999	)		833
Reclamation payments		(10,050	)		(24,547	)
Other		33,510			(22,751	)
Other operating items	$	(139,526	)	$	13,116

25. Share-based compensation plans

The Company has the following equity-settled plans:

A. Stock option plan

The Company has established a stock option plan under which options to purchase common shares may be granted to employees of Cameco. Options granted under the stock option plan have an exercise price of not less than the closing price quoted on the Toronto Stock Exchange (TSX) for the common shares of Cameco on the trading day prior to the date on which the option is granted. The options vest over three years and expire eight years from the date granted.

The aggregate number of common shares that may be issued pursuant to the Cameco stock option plan shall not exceed 43,017,198 of which 27,554,787 shares have been issued.

Stock option transactions for the respective years were as follows:

(Number of options)	2013			2012
Beginning of year		9,517,840			8,526,090
Options granted		1,840,932			2,097,573
Options forfeited		(1,414,493	)		(500,852	)
Options exercised [note 18]		(126,836	)		(604,971	)
End of year		9,817,443			9,517,840
Exercisable		6,279,629			5,964,201

Weighted average exercise prices were as follows:

	2013		2012
Beginning of year	$	31.20	$	32.47
Options granted		22.00		21.14
Options forfeited		28.94		34.22
Options exercised		19.52		11.61
End of year	$	29.95	$	31.20
Exercisable	$	33.30	$	33.53

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Total options outstanding and exercisable at December 31, 2013 were as follows:

			Options outstanding				Options exercisable
Option price per share	Number		Weighted average remaining life		Weighted average exercisable price		Number		Weighted average exercisable price
$15.79 - 34.99		5,962,358		5.6	$	22.84		2,892,297	$	24.10
$35.00 - 54.38		3,855,085		2.6		40.96		3,387,332		41.15
		9,817,443						6,279,629

The foregoing options have expiry dates ranging from March 1, 2014 to February 28, 2021.

Non-vested stock option transactions for the respective years were as follows:

(Number of options)	2013			2012
Beginning of year		3,553,639			2,969,673
Options granted		1,840,932			2,097,573
Options forfeited		(200,546	)		(88,868	)
Options vested		(1,656,211	)		(1,424,739	)
End of year		3,537,814			3,553,639

B. Executive performance share unit (PSU)

The Company has established a PSU plan whereby it provides each plan participant an annual grant of PSUs in an amount determined by the board. Each PSU represents one phantom common share that entitles the participant to a payment of one Cameco common share purchased on the open market, or cash at the board’s discretion, at the end of each three-year period if certain performance and vesting criteria have been met. The final value of the PSUs will be based on the value of Cameco common shares at the end of the three-year period and the number of PSUs that ultimately vest. Vesting of PSUs at the end of the three-year period will be based on total shareholder return over the three years, Cameco’s ability to meet its annual cash flow from operations targets and whether the participating executive remains employed by Cameco at the end of the three-year vesting period. As of December 31, 2013, the total number of PSUs held by the participants after adjusting for forfeitures on retirement was 559,401 (2012—350,240).

C. Executive restricted share unit (RSU)

In 2011, the Company established an RSU plan whereby it provides each plan participant an annual grant of RSUs in an amount determined by the board. Each RSU represents one phantom common share that entitles the participant to a payment of one Cameco common share purchased on the open market, or cash at the board’s discretion. The final value of the RSUs will be based on the value of Cameco common shares at the end of the three-year vesting period. As of December 31, 2013, the total number of RSUs held by the participants was 70,000 (2012—70,000). There were no grants of RSUs in 2013.

D. Employee share ownership plan

Cameco also has an employee share ownership plan, whereby both employee and Company contributions are used to purchase shares on the open market for employees. The Company’s contributions are expensed during the year of contribution. Under the plan, employees have the opportunity to participate in the program to a maximum of 6% of eligible earnings each year with Cameco matching the first 3% of employee-paid shares by 50%. Cameco contributes $1,000 of shares annually to each employee that is enrolled in the plan. Shares purchased with Company contributions and with dividends paid on such shares become unrestricted 12 months from the date on which such shares were purchased. At December 31, 2013, there were 3,718 participants in the plan (2012—3,913). The total number of shares purchased in 2013 with Company contributions was 278,349 shares (2012—265,921). In 2013, the Company’s contributions totalled $5,281,000 (2012—$5,230,000).

46

Cameco records compensation expense under its equity-settled plans with an offsetting credit to contributed surplus, to reflect the estimated fair value of units granted to employees. During the period the Company recognized the following expenses under these plans:

	2013		2012
Stock option plan	$	13,322	$	14,247
Performance share unit plan		5,092		2,709
Restricted share unit plan		594		594
Employee share ownership plan		5,281		5,230
End of year	$	24,289	$	22,780

Fair value measurement of equity-settled plans

The fair value of the units granted through the PSU plan was determined based on Monte Carlo simulation, and the fair value of all other equity-settled payment plans was measured based on the Black-Scholes option-pricing model. Expected volatility is estimated by considering historic average share price volatility.

The inputs used in the measurement of the fair values at grant date of the equity-settled share-based payment plans were as follows:

	Stock option plan			PSUs
Number of options granted		1,840,932			308,950
Average strike price	$	22.00			—
Expected dividend	$	0.40			—
Expected volatility		41	%		34	%
Risk-free interest rate		1.2	%		1.1	%
Expected life of option		4.4 years			3 years
Expected forfeitures		8	%		0	%
Weighted average grant date fair values	$	6.51		$	21.45

In addition to these inputs, other features of the PSU grant were incorporated into the measurement of fair value. The market condition based on total shareholder return was incorporated by utilizing a Monte Carlo simulation. The non-market criteria relating to realized selling prices, production targets and cost control have been incorporated into the valuation at grant date by reviewing prior history and corporate budgets.

The Company has the following cash-settled plans:

A. Deferred share unit (DSU)

Cameco offers a DSU plan to non-employee directors. A DSU is a notional unit that reflects the market value of a single common share of Cameco. 60% of each director’s annual retainer is paid in DSUs. In addition, on an annual basis, directors can elect to receive 25%, 50%, 75% or 100% of the remaining 40% of their annual retainer and any additional fees in the form of DSUs. If a director meets their ownership requirements, the director may elect to take 25%, 50%, 75% or 100% of their annual retainer and any fees in cash, with the balance, if any, to be paid in DSUs. Each DSU fully vests upon award. The DSUs will be redeemed for cash upon a director leaving the board. The redemption amount will be based upon the weighted average of the closing prices of the common shares of Cameco on the TSX for the last 20 trading days prior to the redemption date multiplied by the number of DSUs held by the director. As of December 31, 2013, the total number of DSUs held by participating directors was 523,855 (2012—457,277).

47

B. Phantom stock option

Cameco makes annual grants of bonuses to eligible non-North American employees in the form of phantom stock options. Employees receive the equivalent value of shares in cash when exercised. Options granted under the phantom stock option plan have an award value equal to the closing price quoted on the TSX for the common shares of Cameco on the trading day prior to the date on which the option is granted. The options vest over three years and expire eight years from the date granted. As of December 31, 2013, the number of options held by participating employees was 239,885 (2012—248,440) with exercise prices ranging from $19.37 to $46.88 per share (2012—$19.37 to $46.88) and a weighted average exercise price of $31.22 (2012—$32.13).

Cameco has recognized the following expenses under its cash-settled plans:

	2013		2012
Deferred share unit plan	$	1,192	$	352
Phantom stock option plan		80		325
	$	1,272	$	677

At December 31, 2013, a liability of $12,112,000 (2012—$9,665,000) was included in the consolidated statements of financial position to recognize accrued but unpaid expenses for cash-settled plans.

Fair value measurement of cash-settled plans

The fair value of all cash-settled payment plans was measured based on the Black-Scholes option-pricing model. Expected volatility is estimated by considering historic average share price volatility. The inputs used in the measurement of the fair values at measurement date of the cash-settled share-based payment plans were as follows:

	Grant date March 1, 2013			Reporting date December 31, 2013
Number of units		49,725			239,885
Average strike price	$	22.00		$	31.22
Expected dividend	$	0.40		$	0.40
Expected volatility		44	%		32	%
Risk-free interest rate		1.3	%		1.7	%
Expected life of option		5 years			3.3 years
Expected forfeitures		8	%		8	%
Weighted average measurement date fair values	$	6.86		$	3.44

26. Pension and other post-retirement benefits

Cameco maintains both defined benefit and defined contribution plans providing pension benefits to substantially all of its employees. All regular and temporary employees participate in a registered defined contribution plan except for one employee who participates in a registered defined benefit plan. In addition, all Canadian-based executives participate in a non-registered supplemental executive pension plan which is also a defined benefit plan. This plan is registered under the Pension Benefits Standard Act, 1985.

Under the supplemental executive pension plan, Cameco provides a lump sum benefit equal to the present value of a lifetime pension benefit based on the executive’s length of service and final average earnings. The plan provides for unreduced benefits to be paid at the normal retirement age of 65, however unreduced benefits could be paid if the executive was at least 60 years of age and had 20 years of service at retirement. This program provides for a benefit determined by a formula based on earnings and service, reduced by the benefits payable under the registered base plan. In 2013, there was a plan amendment wherein Cameco’s funding to the supplemental plan was replaced by a letter of credit held by the plan’s trustee. The face amount of the letter of credit will be determined each year based on the wind-up liabilities of the supplemental plan, less any plan assets currently held with the trustee. A valuation will be required annually to determine the letter of credit amount. Benefits will continue to be paid from plan assets until the fund is exhausted, at which time Cameco will begin paying benefits from corporate assets.

48

Cameco also maintains non-pension post-retirement plans (“other benefit plans”) which are defined benefit plans that cover such benefits as group life insurance and supplemental health and dental coverage to eligible employees and their dependants. The costs related to these plans are charged to earnings in the period during which the employment services are rendered. These plans are funded by Cameco as benefit claims are made.

The board of directors of Cameco has final responsibility and accountability for the Cameco retirement programs. The board is ultimately responsible for managing the programs to comply with applicable legislation, providing oversight over the general functions and setting certain policies.

Cameco expects to pay $455,000 in contributions and letter of credit fees to its defined benefit plans in 2014.

The post-retirement plans expose Cameco to actuarial risks, such as longevity risk, market risk, interest rate risk, liquidity risk and foreign currency risk. The other benefit plans expose Cameco to risks of higher supplemental health and dental utilization than expected. However, the other benefit plans have limits on Cameco’s annual benefits payable.

The effective date of the most recent valuations for funding purposes on the registered defined benefit pension plans is January 1, 2012. The next planned effective date for valuations is January 1, 2015.

Cameco has more than one defined benefit plan and has generally provided aggregated disclosures in respect of these plans, on the basis that these plans are not exposed to materially different risks. Information relating to Cameco’s defined benefit plans is shown in the following table:

	Pension benefit plans						Other benefit plans
	2013			2012			2013			2012
Fair value of plan assets, beginning of year	$	20,167		$	20,614		$	—		$	—
Interest income on plan assets		791			950			—			—
Return on assets excluding interest income		(640	)		(448	)		—			—
Employer contributions		123			34			—			—
Benefits paid		(5,024	)		(968	)		—			—
Administrative costs paid		(15	)		(15	)
Fair value of plan assets, end of year	$	15,402		$	20,167		$	—		$	—
Defined benefit obligation, beginning of year	$	37,497		$	44,111		$	15,317		$	16,276
Acquisition [note 6]		11,560			—			—			—
Current service cost		1,809			1,717			1,016			834
Interest cost		1,926			1,819			733			737
Actuarial loss (gain) arising from:
- demographic assumptions		1,752			—			558			(390	)
- financial assumptions		(3,705	)		895			(1,474	)		(1,034	)
- experience adjustment		(1,827	)		(98	)		1,471			(126	)
Past service cost		(605	)		—			—			—
Benefits paid		(5,558	)		(10,949	)		(674	)		(980	)
Foreign exchange		1,537			2			—			—
Defined benefit obligation, end of year	$	44,386		$	37,497		$	16,947		$	15,317
Defined benefit liability [note 16]	$	(28,984	)	$	(17,330	)	$	(16,947	)	$	(15,317	)

49

The percentages of the total fair value of assets in the pension plans for each asset category at December 31 were as follows:

	Pension benefit plans
	2013			2012
Asset category (i)
Canadian equity securities		8	%		10	%
Global equity securities		15	%		18	%
Canadian fixed income		21	%		24	%
Other (ii)		56	%		48	%
Total		100	%		100	%

(i) The defined benefit plan assets contain no material amounts of related party assets at December 31, 2013 and 2012 respectively.

(ii) Relates to the value of the refundable tax account held by the Canada Revenue Agency. The refundable total is approximately equal to half of the sum of the realized investment income plus employer contributions less half of the benefits paid by the plan.

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The following represents the components of net pension and other benefit expense included primarily as part of administration:

	Pension benefit plans					Other benefit plans
	2013			2012		2013		2012
Current service cost	$	1,809		$	1,717	$	1,016	$	834
Net interest cost		1,135			869		733		737
Past service cost		(605	)		—		—		—
Administration cost		15			15		—		—
Defined benefit expense		2,354			2,601		1,749		1,571
Defined contribution pension expense		16,441			16,114		—		—
Net pension and other benefit expense	$	18,795		$	18,715	$	1,749	$	1,571

The total amount of actuarial losses (gains) recognized in other comprehensive income is:

	Pension benefit plans					Other benefit plans
	2013			2012		2013		2012
Actuarial loss (gain)	$	(3,780	)	$	808	$	555	$	(1,550	)
Return on plan assets excluding interest income		640			448		—		—
	$	(3,140	)	$	1,256	$	555	$	(1,550	)

The assumptions used to determine the Company’s defined benefit obligation and net pension and other benefit expense were as follows at December 31 (expressed as weighted averages):

	Pension benefit plans						Other benefit plans
	2013			2012			2013			2012
Discount rate—obligation		4.4	%		4.0	%		4.8	%		4.0	%
Discount rate—expense		3.8	%		4.5	%		4.0	%		4.5	%
Rate of compensation increase		3.3	%		3.0	%		—			—
Initial health care cost trend rate		—			—			7.0	%		7.0	%
Cost trend rate declines to		—			—			5.0	%		5.0	%
Year the rate reaches its final level		—			—			2018			2018
Dental care cost trend rate		—			—			5.0	%		5.0	%

At December 31, 2013, the weighted-average duration of the defined benefit obligation for the pension plans was 16.6 years (2012—15.2 years) and for the other benefit plans was 13.2 years (2012—13.1 years).

A 1% change at the reporting date to one of the relevant actuarial assumptions, holding other assumptions constant, would have affected the defined benefit obligation by the following:

	Pension benefit plans						Other benefit plans
	Increase			Decrease			Increase			Decrease
Discount rate	$	(4,589	)	$	5,883		$	(1,781	)	$	2,189
Rate of compensation increase	$	1,852		$	(1,638	)		n/a			n/a

A 1% change in any of the other assumptions would not have a significant impact on the defined benefit obligation.

The methods and assumptions used in preparing the sensitivity analyses are the same as the methods and assumptions used in determining the financial position of Cameco’s plans as at December 31, 2013. The sensitivity analyses are determined by varying the sensitivity assumption and leaving all other assumptions unchanged. Therefore, the sensitivity analyses do not recognize any interdependence in the assumptions. The methods and assumptions used in determining the above sensitivity are consistent with the methods and assumptions used in the previous year.

51

In addition, an increase of one year in the expected lifetime of plan participants in the pension benefit plans would increase the defined benefit obligation by $884,200.

To measure the longevity risk for these plans, the mortality rates were reduced such that the average life expectancy for all members increased by one year. The reduced mortality rates were subsequently used to remeasure the defined benefit obligation of the entire plan.

27. Financial instruments and related risk management

Cameco is exposed in varying degrees to a variety of risks from its use of financial instruments. Management and the board of directors, both separately and together, discuss the principal risks of our businesses. The board sets policies for the implementation of systems to manage, monitor and mitigate identifiable risks. Cameco’s risk management objective in relation to these instruments is to protect and minimize volatility in cash flow. The types of risks Cameco is exposed to, the source of risk exposure and how each is managed is outlined below.

Market risk

Market risk is the risk that changes in market prices, such as commodity prices, foreign currency exchange rates and interest rates, will affect the Company’s earnings or the fair value of its financial instruments. Cameco engages in various business activities which expose the Company to market risk. As part of its overall risk management strategy, Cameco uses derivatives to manage some of its exposures to market risk that result from these activities.

Derivative instruments may include financial and physical forward contracts. Such contracts may be used to establish a fixed price for a commodity, an interest-bearing obligation or a cash flow denominated in a foreign currency. Market risks are monitored regularly against defined risk limits and tolerances.

Cameco’s actual exposure to these market risks is constantly changing as the Company’s portfolios of foreign currency and commodity contracts change. Changes in fair value or cash flows based on market variable fluctuations cannot be extrapolated as the relationship between the change in the market variable and the change in fair value or cash flow may not be linear.

The types of market risk exposure and the way in which such exposure is managed are as follows:

A. Commodity price risk

As a significant producer and supplier of uranium, nuclear fuel processing and electricity, Cameco bears significant exposure to changes in prices for these products. A substantial change in prices will affect the Company’s net earnings and operating cash flows. Prices for Cameco’s products are volatile and are influenced by numerous factors beyond the Company’s control, such as supply and demand fundamentals, geopolitical events and, in the case of electricity prices, weather.

Cameco’s sales contracting strategy focuses on reducing the volatility in future earnings and cash flow, while providing both protection against decreases in market price and retention of exposure to future market price increases. To mitigate the risks associated with the fluctuations in the market price for uranium products, Cameco seeks to maintain a portfolio of uranium product sales contracts with a variety of delivery dates and pricing mechanisms that provide a degree of protection from pricing volatility.

Cameco does not hold any financial instruments that expose the Company to commodity price risk as of the reporting date.

B. Foreign exchange risk

The relationship between the Canadian and US dollar affects financial results of the uranium business as well as the fuel services business. Sales of uranium product, conversion and fuel manufacturing services are routinely denominated in US dollars while production costs are largely denominated in Canadian dollars.

52

Cameco attempts to provide some protection against exchange rate fluctuations by planned hedging activity designed to smooth volatility. To mitigate risks associated with foreign currency, Cameco enters into forward sales contracts to establish a price for future delivery of the foreign currency. These forward sales contracts are not designated as hedges and are recorded at fair value with changes in fair value recognized in earnings. Cameco also has a natural hedge against US currency fluctuations because a portion of its annual cash outlays, including purchases of uranium and conversion services, is denominated in US dollars.

Cameco holds a number of financial instruments denominated in foreign currencies that expose the Company to foreign exchange risk. Cameco measures its exposure to foreign exchange risk on financial instruments as the change in carrying values that would occur as a result of reasonably possible changes in foreign exchange rates, holding all other variables constant. As of the reporting date, the Company has determined its pre-tax exposure to foreign currency exchange risk on financial instruments to be as follows based on a 5% weakening of the Canadian dollar:

	Carrying value
	Currency	(Cdn)			Gain (loss)
Cash and cash equivalents	KZT	$	10,160		$	508
Cash and cash equivalents	USD		21,342			1,067
Accounts receivable	USD		393,067			19,653
Long-term receivables, investments and other	USD		95,319			4,766
Bank overdraft	EUR		(41,226	)		(2,060	)
Accounts payable and accrued liabilities	USD		(425,491	)		(21,275	)
Short-term debt	EUR		(14,655	)		(732	)
Net foreign currency derivatives	USD		(27,132	)		(83,227	)

A 5% strengthening of the Canadian dollar against the currencies above at December 31, 2013 would have had an equal but opposite effect on the amounts shown above, assuming all other variables remained constant.

C. Interest rate risk

The Company has a strategy of minimizing its exposure to interest rate risk by maintaining target levels of fixed and variable rate borrowings. The proportions of outstanding debt carrying fixed and variable interest rates are reviewed by senior management to ensure that these levels are within approved policy limits. At December 31, 2013, the proportion of Cameco’s outstanding debt that carries fixed interest rates is 84% (2012—87%).

Cameco is exposed to interest rate risk through its interest rate swap contracts whereby fixed rate payments on a notional amount of $155,000,000 of the Series C senior unsecured debentures were swapped for variable rate payments. The swaps terminate on March 16, 2015. Under the terms of the swaps, Cameco makes interest payments based on the three-month Canada Dealer Offered Rate plus an average margin of 1.83% and receives fixed interest payments of 4.7%. To mitigate this risk, Cameco entered into interest rate cap arrangements, effective March 18, 2013, whereby the three-month Canada Dealer Offered Rate was capped at 5.0% such that total variable payments will not exceed, on average, 6.83%. At December 31, 2013, the fair value of Cameco’s interest rate swaps and caps was $3,616,000 (2012—$5,453,000).

Cameco is also exposed to interest rate risk on its loan facility with Inkai and on NUKEM’s multicurrency revolving loan facility due to the variable nature of the interest rates contained in the terms therein.

53

Cameco measures its exposure to interest rate risk as the change in cash flows that would occur as a result of reasonably possible changes in interest rates, holding all other variables constant. As of the reporting date, the Company has determined the impact on earnings of a 1% increase in interest rate on variable rate financial instruments to be as follows:

	Gain (loss)
Interest rate contracts	$	(388	)
Advances receivable from Inkai		918
NUKEM loan facility		(517	)

Counterparty credit risk

Counterparty credit risk is associated with the ability of counterparties to satisfy their contractual obligations to Cameco, including both payment and performance. Cameco’s sales of uranium product, conversion and fuel manufacturing services expose the Company to the risk of non-payment.

Cameco manages the risk of non-payment by monitoring the credit worthiness of our customers and seeking pre-payment or other forms of payment security from customers with an unacceptable level of credit risk. To mitigate risks associated with certain financial assets, Cameco will hold positions with a variety of large creditworthy institutions.

The maximum exposure to credit risk, as represented by the carrying amount of the financial assets, at December 31 was:

			(Revised - note 3)
	2013		2012
Cash and cash equivalents	$	229,135	$	749,499
Short-term investments		—		49,535
Accounts receivable		416,031		389,871
Advances receivable from Inkai [note 32]		95,319		87,264
Derivative assets		7,391		22,453

At December 31, 2013, there were no significant concentrations of credit risk and no amounts were held as collateral. Historically, Cameco has experienced minimal customer defaults and, as a result, considers the credit quality of its accounts receivable to be high. All accounts receivable at the reporting date are neither past due nor impaired.

Liquidity risk

Financial liquidity represents Cameco’s ability to fund future operating activities and investments. Cameco ensures that there is sufficient capital in order to meet short-term business requirements, after taking into account cash flows from operations and the Company’s holdings of cash and cash equivalents. The Company believes that these sources will be sufficient to cover the likely short-term and long-term cash requirements.

54

The table below outlines the Company’s available debt facilities at December 31, 2013:

	Total amount		Outstanding and committed		Amount available
Unsecured revolving credit facility	$	1,250,000	$	—	$	1,250,000
Letter of credit facility		798,774		790,944		7,830
Inkai revolving credit facility (Cameco’s share)		12,763		—		12,763
NUKEM multicurrency revolving loan facility		146,550		56,618		89,932

The tables below present a maturity analysis of Cameco’s financial liabilities, including principal and interest, based on the expected cash flows from the reporting date to the contractual maturity date:

	Carrying amount		Contractual cash flows		Due in less than 1 year		Due in 1-3 years		Due in 3-5 years		Due after 5 years
Bank overdraft	$	41,226	$	41,226	$	41,226	$	—	$	—	$	—
Accounts payable and accrued liabilities		437,940		437,940		437,940		—		—		—
Short-term debt		50,230		50,230		50,230		—		—		—
Long-term debt		1,293,383		1,300,000		—		300,000		—		1,000,000
Foreign currency contracts		30,907		30,907		30,907		—		—		—
Total contractual repayments	$	1,853,686	$	1,860,303	$	560,303	$	300,000	$	—	$	1,000,000

	Total		Due in less than 1 year		Due in 1-3 years		Due in 3-5 years		Due after 5 years
Interest on short-term debt	$	141	$	141	$	—	$	—	$	—
Interest on long-term debt		480,910		62,540		110,980		96,880		210,510
Total interest payments	$	481,051	$	62,681	$	110,980	$	96,880	$	210,510

55

Measurement of fair values

A. Accounting classifications and fair values

The following tables summarize the carrying amounts and accounting classifications of Cameco’s financial instruments at the reporting date:

As at December 31, 2013

	Fair value through profit or loss			Loans and receivables		Available for sale		Other financial liabilities			Total
Financial assets
Cash and cash equivalents	$	—		$	229,135	$	—	$	—		$	229,135
Accounts receivable		—			431,375		—		—			431,375
Derivative assets [note 11]
Foreign currency contracts		3,775			—		—		—			3,775
Interest rate contracts		3,616			—		—		—			3,616
Investments in equity securities [note 11]		—			—		22,805		—			22,805
Advances receivable from Inkai [note 32]		—			95,319		—		—			95,319
		7,391			755,829		22,805		—			786,025
Financial liabilities
Bank overdraft		41,226			—		—		—			41,226
Accounts payable and accrued liabilities		—			—		—		437,941			437,941
Short-term debt [note 14]
Commercial paper		—			—		—		24,974			24,974
Promissory note		—			—		—		10,601			10,601
NUKEM short-term loan		—			—		—		14,655			14,655
Derivative liabilities [note 16]
Foreign currency contracts		30,907			—		—		—			30,907
Share purchase options		16			—		—		—			16
Long-term debt [note 15]		—			—		—		1,293,383			1,293,383
		72,149			—		—		1,781,554			1,853,703
Net	$	(64,758	)	$	755,829	$	22,805	$	(1,781,554	)	$	(1,067,678	)

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As at December 31, 2012

	Fair value through profit or loss		Loans and receivables		Available for sale		Other financial liabilities			Total
Financial assets
Cash and cash equivalents	$	—	$	749,499	$	—	$	—		$	749,499
Short-term investments		—		—		49,535		—			49,535
Accounts receivable		—		404,040		—		—			404,040
Derivative assets [note 11]
Foreign currency contracts		17,000		—		—		—			17,000
Interest rate contracts		5,453		—		—		—			5,453
Investment in equity securities [note 11]		—		—		20,599		—			20,599
Advances receivable from Inkai [note 32]		—		87,264		—		—			87,264
		22,453		1,240,803		70,134		—			1,333,390
Financial liabilities
Accounts payable and accrued liabilities		—		—		—		387,653			387,653
Short-term debt [note 14]
Commercial paper		—		—		—		24,984			24,984
Promissory note		—		—		—		42,106			42,106
Derivative liabilities [note 16]
Foreign currency contracts		1,954		—		—		—			1,954
Long-term debt [note 15]		—		—		—		1,292,440			1,292,440
		1,954		—		—		1,747,183			1,749,137
Net	$	20,499	$	1,240,803	$	70,134	$	(1,747,183	)	$	(415,747	)

Cameco does not have any financial instruments classified as held-for-trading, or held-to-maturity as of the reporting date.

The following tables summarize the carrying amounts and fair values of Cameco’s financial instruments that are measured at fair value, including their levels in the fair value hierarchy:

As at December 31, 2013

				Fair value
	Carrying value			Level 1			Level 2			Total
Derivative assets [note 11]
Foreign currency contracts	$	3,775		$	—		$	3,775		$	3,775
Interest rate contracts		3,616			—			3,616			3,616
Derivative liabilities [note 16]
Foreign currency contracts		(30,907	)		—			(30,907	)		(30,907	)
Share purchase options		(16	)		(16	)		—			(16	)
Net	$	(23,532	)	$	(16	)	$	(23,516	)	$	(23,532	)

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As at December 31, 2012 (revised – note 3)

				Fair value
	Carrying value			Level 1		Level 2			Total
Short-term investments	$	49,535		$	49,535	$	—		$	49,535
Derivative assets [note 11]
Foreign currency contracts		17,000			—		17,000			17,000
Interest rate contracts		5,453			—		5,453			5,453
Derivative liabilities [note 16]
Foreign currency contracts		(1,954	)		—		(1,954	)		(1,954	)
Net	$	70,034		$	49,535	$	20,499		$	70,034

The preceding tables exclude fair value information for financial instruments whose carrying amounts is a reasonable approximation of fair value.

There were no transfers between level 1, level 2, or level 3 during the period. Cameco does not have any financial instruments that are classified as level 3 as of the reporting date.

B. Financial instruments measured at fair value

Cameco measures its short-term investments, derivative financial instruments, and certain investments in equity securities at fair value. Short-term investments and investments in publicly held equity securities are classified as a recurring level 1 fair value measurement, and derivative financial instruments are classified as a recurring level 2 fair value measurement.

Short-term investments represent available-for-sale money market instruments. The fair value of these instruments is determined using quoted market yields as of the reporting date. The fair value of investments in equity securities is determined using quoted share prices observed in the principal market for the securities as of the reporting date.

Foreign currency derivatives consist of foreign currency forward contracts, and foreign currency swaps. The fair value of foreign currency derivatives is measured using a market approach, based on the difference between contracted foreign exchange rates and quoted forward exchange rates as of the reporting date.

Interest rate derivatives consist of interest rate swap contracts, and interest rate caps. The fair value of interest rate swaps is determined by discounting expected future cash flows from the contracts. The future cash flows are determined by measuring the difference between fixed interest payments to be received and floating interest payments to be made to the counterparty based on Canada Dealer Offer Rate forward interest rate curves. The fair value of interest rate caps is determined based on broker quotes observed in active markets at the reporting date.

Where applicable, the fair value of the derivatives reflects the credit risk of the instrument, and includes adjustments to take into account the credit risk of the Company and counterparty. These adjustments are based on credit ratings and yield curves observed in active markets at the reporting date.

C. Financial instruments not measured at fair value

The carrying value of Cameco’s cash and cash equivalents, receivables, payables and accrued liabilities is assumed to approximate the fair value as a result of the short-term nature of the instruments. The carrying value of Cameco’s short-term debt (commercial paper and promissory notes), and long-term debt (debentures) is assumed to approximate the fair value as a result of the variable interest rate associated with the instruments, or the fixed interest rate of the instruments being similar to market rates.

The fair value of Cameco’s privately held equity securities are not disclosed because of the unavailability of quoted market price in an active market. Cameco does not currently have plans to dispose of this investment.

58

Derivatives

The following tables summarize the fair value of derivatives and classification on the consolidated statements of financial position:

				(Revised - note 3)
	2013			2012
Non-hedge derivatives:
Foreign currency contracts	$	(27,132	)	$	15,046
Interest rate contracts		3,616			5,453
Share purchase options		(16	)		—
Net	$	(23,532	)	$	20,499
Classification:
Current portion of long-term receivables, investments and other [note 11]	$	3,775		$	17,000
Long-term receivables, investments and other [note 11]		3,616			5,453
Current portion of other liabilities [note 16]		(30,923	)		(1,954	)
Net	$	(23,532	)	$	20,499

The following tables summarize different components of the gains (losses) on derivatives included in net earnings:

				(Revised - note 3)
	2013			2012
Non-hedge derivatives:
Foreign currency contracts	$	(62,578	)	$	42,063
Embedded derivatives—sales contracts		—			138
Interest rate contracts		624			(785	)
Share purchase options		(16	)		—
Net	$	(61,970	)	$	41,416

28. Capital management

Cameco’s capital structure reflects our vision and the environment in which we operate. We seek growth through development and expansion of existing assets by acquisition. Our capital resources are managed to support achievement of our goals. The overall objectives for managing capital in 2013 remained unchanged from the prior comparative period.

Cameco’s management considers its capital structure to consist of bank overdrafts, long-term debt, short-term debt (net of cash and cash equivalents and short-term investments), non-controlling interest and shareholders’ equity.

59

The capital structure at December 31 was as follows:

				(Revised - note 3)
	2013			2012
Bank overdrafts	$	41,226		$	—
Long-term debt [note 15]		1,293,383			1,292,440
Short-term debt [note 14]		50,230			67,090
Cash and cash equivalents		(229,135	)		(749,499	)
Short-term investments		—			(49,535	)
Net debt		1,155,704			560,496
Non-controlling interest		1,129			580
Shareholders’ equity		5,348,265			4,941,384
Total equity		5,349,394			4,941,964
Total capital	$	6,505,098		$	5,502,460

Cameco is bound by certain covenants in its general credit facilities. These covenants place restrictions on total debt, including guarantees, and set minimum levels for net worth. As of December 31, 2013, Cameco met these requirements.

The terms of NUKEM’s revolving loan facility contain a financial covenant that places restrictions on total debt and working capital balances. The facility also requires Cameco, as guarantor, to maintain a minimum credit rating. As of December 31, 2013 the Company is in compliance with all requirements under this facility.

29. Segmented information

Cameco has four reportable segments: uranium, fuel services, electricity and NUKEM. The uranium segment involves the exploration for, mining, milling, purchase and sale of uranium concentrate. The fuel services segment involves the refining, conversion and fabrication of uranium concentrate and the purchase and sale of conversion services. The electricity segment involves the generation and sale of electricity. The NUKEM segment acts as a market intermediary between uranium producers and nuclear-electric utilities.

Cameco’s reportable segments are strategic business units with different products, processes and marketing strategies.

Accounting policies used in each segment are consistent with the policies outlined in the summary of significant accounting policies. Segment revenues, expenses and results include transactions between segments incurred in the ordinary course of business. These transactions are priced on an arm’s length basis and are eliminated on consolidation.

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A. Business segments

For the year ended December 31, 2013

	Uranium		Fuel services		NUKEM			(i) Electricity			(i) Adjustments			Other			Total
Revenue	$	1,632,508	$	319,157	$	464,592		$	432,857		$	(432,857	)	$	22,466		$	2,438,723
Expenses
Cost of products and services sold		869,137		240,746		419,771			245,374			(245,374	)		19,584			1,549,238
Depreciation and amortization		212,881		26,241		25,459			70,721			(70,721	)		18,175			282,756
Cost of sales		1,082,018		266,987		445,230			316,095			(316,095	)		37,759			1,831,994
Gross profit (loss)		550,490		52,170		19,362			116,762			(116,762	)		(15,293	)		606,729
Administration		—		—		15,240			—			—			169,736			184,976
Impairment charge		70,159		—		—			—			—			—			70,159
Exploration		72,833		—		—			—			—			—			72,833
Research and development		—		—		—			—			—			7,302			7,302
Loss on sale of assets		6,766		—		—			—			—			—			6,766
Finance costs		—		—		7,936			8,532			(8,532	)		54,185			62,121
Losses (gains) on derivatives		—		—		(10,215	)		—			—			72,185			61,970
Finance income		—		—		(69	)		(5,941	)		5,941			(6,898	)		(6,967	)
Share of earnings from BPLP		—		—		—			—			(109,553	)		—			(109,553	)
Share of loss (earnings) from equity-accounted investees		1,033		13,074		—			—			—			(3,240	)		10,867
Other expense		16,587		—		—			4,618			(4,618	)		1,739			18,326
Earnings (loss) before income taxes		383,112		39,096		6,470			109,553			—			(310,302	)		227,929
Income tax recovery																		(89,758	)
Net earnings																	$	317,687
Capital expenditures for the year	$	635,152	$	10,499	$	133,924		$	—		$	—		$	—		$	779,575

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For the year ended December 31, 2012 (revised - note 3)

	Uranium			Fuel services		(i) Electricity			(i) Adjustments			Other			Total
Revenue	$	1,571,105		$	291,042	$	470,018		$	(470,018	)	$	28,513		$	1,890,660
Expenses
Cost of products and services sold		883,741			223,022		228,847			(228,847	)		26,500			1,133,263
Depreciation and amortization		172,914			26,902		69,678			(69,678	)		17,565			217,381
Cost of sales		1,056,655			249,924		298,525			(298,525	)		44,065			1,350,644
Gross profit (loss)		514,450			41,118		171,493			(171,493	)		(15,552	)		540,016
Administration		—			—		—			—			180,900			180,900
Impairment charge		168,000			—		—			—			—			168,000
Exploration		97,260			—		—			—			—			97,260
Research and development		—			—		—			—			9,301			9,301
Gain on sale of assets		(1,660	)		—		—			—			—			(1,660	)
Finance costs		—			—		14,788			(14,788	)		67,654			67,654
Gains on derivatives		—			—		—			—			(41,416	)		(41,416	)
Finance income		—			—		(6,446	)		6,446			(13,934	)		(13,934	)
Share of earnings from BPLP		—			—		—			(157,846	)		—			(157,846	)
Share of loss (earnings) from equity-accounted investees		3,230			3,054		—			—			(388	)		5,896
Other expense (income)		35,746			—		5,305			(5,305	)		(11,000	)		24,746
Earnings (loss) before income taxes		211,874			38,064		157,846			—			(206,669	)		201,115
Income tax recovery																(50,641	)
Net earnings															$	251,756
Capital expenditures for the year	$	1,232,654		$	15,284	$	—		$	—		$	—		$	1,247,938

(i) Consistent with the presentation of financial information for internal management purposes, Cameco’s pro-rata share of BPLP’s financial results have been presented as a separate segment. In accordance with IFRS, this investment is accounted for by the equity method of accounting in these consolidated financial statements and the associated revenues and expenses are eliminated in the “Adjustments” column.

B. Geographic segments

Revenue is attributed to the geographic location based on the location of the entity providing the services. The Company’s revenue from external customers is as follows:

			(Revised - note 3)
	2013		2012
Canada	$	191,398	$	270,834
Germany		232,296		—
United States		2,015,029		1,619,826
	$	2,438,723	$	1,890,660

62

The Company’s non-current assets, excluding deferred tax assets and financial instruments, by geographic location are as follows:

			(Revised - note 3)
	2013		2012
Canada	$	3,868,871	$	3,658,615
United States		371,705		336,534
Germany		105,293		—
Australia		645,952		702,585
Other		243,203		212,517
	$	5,235,024	$	4,910,251

30. Group entities

The following are the principal subsidiaries and associates of the Company:

	Principal place		Ownership interest
	of business		2013			2012
Subsidiaries:
Cameco Bruce Holdings Inc.		Canada		100	%		100	%
Cameco Bruce Holdings II Inc.		Canada		100	%		100	%
Cameco Fuel Manufacturing Inc.		Canada		100	%		100	%
Cameco Inc.		US		100	%		100	%
Power Resources, Inc.		US		100	%		100	%
Crow Butte Resources, Inc.		US		100	%		100	%
Urtek LLC		US		73	%		58	%
NUKEM Investments GmbH		Germany		100	%		—
Cameco Australia Pty. Ltd.		Australia		100	%		100	%
Cameco Europe Ltd.		Switzerland		100	%		100	%
Cameco Europe (Central Asia) Ltd.		Switzerland		100	%		100	%
Cameco Services Inc.		Barbados		100	%		100	%
Associates
GE-Hitachi Global Laser Enrichment LLC		US		24.00	%		24.00	%
UEX Corporation		Canada		21.95	%		22.58	%

31. Joint operations

Cameco conducts a portion of its exploration, development, mining and milling activities through joint operations located around the world. Operations are governed by agreements that provide for joint control of the strategic operating, investing and financing activities among the partners. These agreements were considered in the determination of joint control. Cameco’s significant Canadian uranium joint operation interests are McArthur River, Key Lake and Cigar Lake. The Canadian uranium joint operations allocate uranium production to each joint operation participant and the joint operation participant derives revenue directly from the sale of such product. The participants in the Inkai joint operation purchase uranium from Inkai and, in turn, derive revenue directly from the sale of such product to third-party customers. Mining and milling expenses incurred by joint operations are included in the cost of inventory.

63

Cameco reflects its proportionate interest in these assets and liabilities as follows:

								(Revised - note 3)
	Principle place of business		Ownership			2013		2012
Total assets
McArthur River		Canada		69.81	%	$	1,034,095	$	1,018,089
Key Lake		Canada		83.33	%		626,090		618,821
Cigar Lake		Canada		50.03	%		1,370,476		1,086,565
Inkai		Kazakhstan		60.00	%		323,404		288,088
						$	3,354,065	$	3,011,563
Total liabilities
McArthur River				69.81	%	$	51,094	$	55,517
Key Lake				83.33	%		149,263		156,400
Cigar Lake				50.03	%		55,718		55,673
Inkai				60.00	%		170,134		159,674
						$	426,209	$	427,264

Through unsecured shareholder loans, Cameco has agreed to fund the development of the Inkai project. Cameco eliminates the loan balances recorded by Inkai and records advances receivable (notes 11 and 32) representing its 40% ownership interest.

32. Related parties

The shares of Cameco are widely held and no shareholder, resident in Canada, is allowed to own more than 25% of the Company’s outstanding common shares, either individually or together with associates. A non-resident of Canada is not allowed to own more than 15%.

Transactions with key management personnel

Key management personnel are those persons that have the authority and responsibility for planning, directing and controlling the activities of the Company, directly or indirectly. Key management personnel of the Company include executive officers, vice-presidents, other senior managers and members of the board of directors.

In addition to their salaries, Cameco also provides non-cash benefits to executive officers and vice-presidents, and contributes to pension plans on their behalf (note 26). Senior management and directors also participate in the Company’s share-based compensation plans (note 25).

Executive officers are subject to terms of notice ranging from three to six months. Upon resignation at the Company’s request, they are entitled to termination benefits up to the lesser of 24 months or the period remaining until age 65. The termination benefits include gross salary plus the target short-term incentive bonus for the year in which termination occurs.

Compensation for key management personnel was comprised of:

			(Revised - note 3)
	2013		2012
Short-term employee benefits	$	21,276	$	19,702
Post-employment benefits		4,415		5,021
Share-based compensation (a)		11,864		8,622
	$	37,555	$	33,345

(a) Excludes deferred share units held by directors (see note 25).

64

Other related party transactions

				(Revised - note 3)						(Revised - note 3)
	Transaction value year ended						Balance outstanding as at
	2013			2012			2013			2012
Sale of goods and services
Joint arrangements
BPLP	$	60,252		$	124,063		$	13,400		$	33,932
Other
Joint arrangements
Interest income (Inkai) (a)		2,053			2,334			95,319			87,264
Associates
Interest expense		(220	)		(919	)		(10,647	)		(42,220	)

(a) Disclosures in respect of transactions with joint arrangements represent the amount of such transactions which do not eliminate on proportionate consolidation.

Cameco has entered into fuel supply agreements with BPLP for the procurement of fabricated fuel. Under these agreements, Cameco will supply uranium, conversion services and fabrication services. Contract terms are at market rates and on normal trade terms.

Through unsecured shareholder loans, Cameco has agreed to fund Inkai’s project development costs as well as further evaluation on block 3. The limit of the loan facilities are $292,150,000 (US) and advances under these facilities bear interest at a rate of LIBOR plus 2%. At December 31, 2013, $224,047,000 (US) of principal and interest was outstanding (2012—$219,277,000 (US)).

In 2008, a promissory note in the amount of $73,344,000 (US) was issued to finance the acquisition of GLE. The promissory note is payable on demand and bears interest at market rates. At December 31, 2013, $10,010,000 (US) of principal and interest was outstanding (2012—$42,436,000 (US)).

33. Subsequent event

On January 30, 2014, Cameco signed an agreement with BPC Generation Infrastructure Trust to sell its 31.6% limited partnership interest in BPLP. The aggregate purchase price for Cameco’s interest in BPLP and certain related entities is $450,000,000 and the effective date for the sale is December 31, 2013. Cameco expects to realize an after tax gain of approximately $129,000,000 on this divestiture. Closing of the transaction is subject to exercise or waiver of the right of first offer held by the other three limited partners and receipt of certain regulatory approvals.

65

EX-99.3

EXHIBIT 99.3

Cameco Corporation

2013 Management’s Discussion and Analysis

February 10, 2014

Management’s discussion and analysis

February 10, 2014

4	THE NUCLEAR FUEL CYCLE
5	ABOUT CAMECO
8	2013 HIGHLIGHTS
11	THE NUCLEAR ENERGY INDUSTRY TODAY
14	THE LONG-TERM VIEW
16	OUR STRATEGY
20	RESPONSIBILITY
26	FINANCIAL RESULTS
54	OUR OPERATIONS AND PROJECTS
84	MINERAL RESERVES AND RESOURCES
90	ADDITIONAL INFORMATION

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our audited consolidated financial statements (financial statements) and notes for the year ended December 31, 2013. The information is based on what we knew as of February 7, 2014.

We encourage you to read our financial statements and notes as you review this MD&A. You can find more information about Cameco, including our financial statements and our most recent annual information form, on our website at cameco.com, on SEDAR at sedar.com or on EDGAR at sec.gov. You should also read our annual information form before making an investment decision about our securities.

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

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

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

Caution about forward-looking information

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

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

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

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

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

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

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

Examples of forward-looking information in this MD&A

• our expectations about 2014 and future global uranium supply, consumption, demand, contracting volumes, number of operable reactors and nuclear generating capacity, including the discussion under the headings Key market facts, the nuclear energy industry today and The long term view

• the discussion under the heading Our strategy , including our expectation that market challenges will continue for the near to medium term

• our 2014 objectives

• our expectations for uranium deliveries in the first quarter and for the balance of 2014

• 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 consolidated outlook for the year and the outlook for our uranium, fuel services and NUKEM segments for 2014

• our expectation that existing cash balances and operating cash flows will meet our anticipated 2014 capital requirements without the need for any significant additional funding

• our expectations for 2014, 2015 and 2016 capital expenditures

• our expectation that in 2014 we will continue to comply with all the covenants in our unsecured revolving credit facility

• our uranium price sensitivity analysis

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

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

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

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

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

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

2     CAMECO CORPORATION

• 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 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

Material assumptions

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

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

• our expected production level and production costs

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

• our expectations regarding spot prices and realized prices for uranium, and other factors discussed on page 42, Price sensitivity analysis: 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 mining and production plans succeed, including the additional jet boring 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, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues (including an inability to renew agreements with unionized employees at McArthur River and Key Lake), strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents or other development or operating risks

MANAGEMENT’S DISCUSSION AND ANALYSIS    3

The nuclear fuel cycle

1 Mining

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

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

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

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

1 Milling

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

2 Refining

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

3 Conversion

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

4 Enrichment

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

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

5 Fuel manufacturing

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

6 Generation

Nuclear reactors are used to generate electricity.

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

Spent fuel management

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

4     CAMECO CORPORATION

About Cameco

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

Strengths

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

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

Business segments

URANIUM

We are one of the world’s largest uranium producers, and in 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.

Product

• uranium concentrates (U₃O₈)

Mineral reserves and resources

Mineral reserves

• approximately 443 million pounds proven and probable

Mineral resources

• approximately 391 million pounds measured and indicated and 289 million pounds inferred

Global exploration

• focused on four continents

• approximately 2.0 million hectares of land

Operating properties

• McArthur River and Key Lake, Saskatchewan

• Rabbit Lake, Saskatchewan

• Smith Ranch-Highland, Wyoming

• Crow Butte, Nebraska

• Inkai, Kazakhstan

Development project

• Cigar Lake, Saskatchewan

Projects under evaluation

• Inkai blocks 1 and 2 production increase, Kazakhstan

• Inkai block 3, Kazakhstan

• Millennium, Saskatchewan

• Yeelirrie, Australia

• Kintyre, Australia

FUEL SERVICES

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

Products

• uranium trioxide (UO₃)

• uranium hexafluoride (UF₆)

(control about 25% of world conversion capacity)

• uranium dioxide (UO₂)

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

Operations

• Blind River refinery, Ontario

(refines uranium concentrates to UO₃)

• Port Hope conversion facility, Ontario

(converts UO₃ to UF₆ or UO₂)

• Cameco Fuel Manufacturing Inc., Ontario

(manufactures fuel bundles and reactor components)

• a toll conversion agreement with Springfields Fuels Ltd.

(SFL), Lancashire, United Kingdom (UK) (to convert UO₃ to UF₆ – expires in 2016)

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. We acquired NUKEM in January, 2013.

Activity

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

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    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.

GLOBAL PRESENCE

6     CAMECO CORPORATION

KEY MARKET FACTS

The 2013 World Energy Outlook predicts that by 2035 electricity consumption will have grown by about 70% from current levels, driven mainly by growth in the developing world as it seeks to diversify sources of energy and provide security of supply.

• At the start of 2014, there were 433 operable commercial nuclear power reactors in 31 countries, and by 2023, we expect that to grow to 526 reactors.

• At the start of 2014, there were 70 reactors under construction in 15 countries, and dozens more planned to begin operation by 2023.

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

• In emerging nuclear countries, construction has begun in the United Arab Emirates (UAE) and Belarus, and planning for first reactors is underway in Turkey, Vietnam, Bangladesh, Poland, Jordan and Saudi Arabia.

• Over the next decade, we expect demand for uranium to grow by an average of 4% per year. To meet global demand, we expect about two-thirds of uranium supply will come from mines that are currently in operation, about 15% from finite sources of secondary supply (mainly government inventories and limited recycling), and about 20% will have to come from new sources of supply.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    7

2013 highlights

The long-term outlook for growth in the nuclear industry remains very strong. Over 70 reactors are under construction at the beginning of 2014, and average annual uranium demand is expected to increase by about 4% over the next decade. However, challenges remain in the near to medium term, and have persisted for longer than anticipated due to the lingering effects of the events in Japan in 2011 and global economic slowdown. In this environment, our previous supply target of 36 million pounds by 2018 is no longer appropriate, and thus, we have eliminated that target. We expect this will allow us greater flexibility to respond to market conditions and deliver the best value until more certainty returns to the market environment.

In spite of the challenging market environment, we demonstrated our strengths again in 2013, exceeding our production target, delivering on our financial guidance and achieving a number of performance records. In particular, with the addition of NUKEM in 2013, our sales were about 42 million pounds, representing about 25% of 2013 reactor consumption.

Strong financial performance

Our financial results remained strong in 2013:

• record annual revenue of $2.4 billion

• annual gross profit of $607 million

• record annual revenue of $1.6 billion from our uranium segment

• record annual average realized price of $49.81 per pound ($48.35 US per pound) in our uranium segment

Net earnings attributable to our equity holders (net earnings) in 2013 were $318 million compared to $253 million in 2012. This $65 million increase in net earnings was the result of:

• the impact of a one-time $168 million write-down of our investment in the Kintyre deposit in 2012

• higher earnings in our fuel services segment as a result of an increase in sales volumes and realized prices

• lower exploration expenditures

• higher tax recoveries due to a decline in pre-tax earnings in Canada

partially offset by:

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

• a $70 million write-down of our Talvivaara asset, due to their weakened financial position and pending corporate restructuring

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

HIGHLIGHTS DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED)	2013		2012		CHANGE
Revenue		2,439		1,891		29	%
Gross profit		607		540		12	%
Net earnings attributable to equity holders		318		253		26	%
$ per common share (diluted)		0.81		0.64		27	%
Adjusted net earnings (non-IFRS, see page 28)		445		434		3	%
$ per common share (adjusted and diluted)		1.12		1.10		2	%
Cash provided by operations (after working capital changes)		530		579		(8	)%

8     CAMECO CORPORATION

Solid progress in our uranium segment this year

In our uranium segment, we achieved record annual production and, in the fourth quarter, record quarterly production, as well as a number of successes at our mining operations and development project. Key highlights:

• record annual production of 23.6 million pounds—2% higher than the guidance we provided in our 2013 third quarter MD&A

• record quarterly production of 7.5 million pounds in the fourth quarter—15% higher than in 2012

• realized benefits of production flexibility provisions in our McArthur River/Key Lake licences, exceeding our annual production target by 4% and setting a new record for annual production from a uranium operation, anywhere in the world, with 20.1 million pounds (100% basis) in 2013

• began commissioning the jet boring system at Cigar Lake, jetting a test cavity in waste rock followed by our first cavity in ore

• in the US, our North Butte satellite operation began production

• the Canadian Nuclear Safety Commission (CNSC) granted an eight-year operating licence for Cigar, and 10-year operating licences for McArthur River, Key Lake and Rabbit Lake

• Inkai received government approval of an amendment to the resource use contract to increase production from blocks 1 and 2 to 5.2 million pounds (3.0 million pounds our share)

• we announced the signing of a collaboration agreement that will strengthen and formalize the relationship between us, AREVA Resources Canada Inc. (AREVA) and the English River First Nation, building on past cooperation and sharing of benefits from our operations

• the government of Saskatchewan announced changes to the provincial royalty system to encourage continued investment in Saskatchewan

• we delivered our first shipments of Canadian uranium to China under the Canada-China Nuclear Co-operation Agreement (NCA)

• the Canadian government announced the signing of the final agreement required to implement the Canada-India NCA, which, once brought into force, will allow us to export Canadian-origin uranium to India

We also continued to advance our exploration activities, spending $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. We spent about $44 million on regional exploration programs, mostly in Saskatchewan, followed by Australia and the United States.

Updates on our other segments and investments

In our fuel services segment, production was 5% higher than in 2012 when we reduced production in response to weak market conditions for UF₆. We also signed new three-year collective agreements with unionized employees at our Port Hope conversion facility.

In our electricity segment, Bruce Power Limited Partnership (BPLP) generated 24.8 terawatt hours (TWh) of electricity, at a capacity factor of 87%. Our share of earnings before taxes was $109 million, a 31% decrease compared to 2012.

On January 31, 2014, we announced the sale of our 31.6% limited partnership interest in BPLP and related entities to BPC Generation Infrastructure Trust, one of the limited partners in BPLP, for $450 million. The 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 approvals.

Our investment in GE-Hitachi Global Laser Enrichment (GLE) continues to progress. GLE is continuing its testing activities and engineering design work for a commercial facility. On November 27, 2013, the US Department of Energy (DOE) announced that it will negotiate with GLE for the sale of its depleted uranium hexafluoride inventory held at their Paducah, Kentucky and Portsmouth, Ohio sites. If negotiations are successful, we expect that definitive agreements would follow.

We completed our acquisition of NUKEM Energy GmbH in January, 2013. NUKEM is one of the world’s leading traders and brokers of nuclear fuel products and services.

MANAGEMENT’S DISCUSSION AND ANALYSIS    9

HIGHLIGHTS			2013		2012		CHANGE
Uranium	Production volume (million lbs)			23.6		21.9		8	%
	Sales volume (million lbs)			32.8		32.9		—
	Average realized price	($US/lb)		48.35		47.72		1	%
		($Cdn/lb)		49.81		47.72		4	%
	Revenue ($ millions)			1,633		1,571		4	%
	Gross profit ($ millions)			550		514		7	%
Fuel services	Production volume (million kgU)			14.9		14.2		5	%
	Sales volume (million kgU)			17.6		16.4		7	%
	Average realized price ($Cdn/kgU)			18.12		17.75		2	%
	Revenue ($ millions)			319		291		10	%
	Gross profit ($ millions)			52		41		27	%
NUKEM	Sales volume U3O8 (million lbs)			8.9		—		—
	Average realized price ($Cdn/lb)			42.26		—		—
	Revenue ($ millions)			465		—		—
	Gross profit (loss) ($ millions)			20		—		—
Electricity	Output (100%) (TWh)			24.8		26.8		(7	)%
	Average realized price ($Cdn/MWh)			54		55		(2	)%
	Revenue (100%)			1,370		1,487		(8	)%
	Our share of earnings before taxes ($ millions)			109		157		(31	)%

SHARES AND STOCK OPTIONS OUTSTANDING

At February 6, 2014, we had:

• 395,627,632 common shares and one Class B share outstanding

• 9,628,635 stock options outstanding, with exercise prices ranging from $15.79 to $54.38

DIVIDEND POLICY

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

10     CAMECO CORPORATION

The nuclear energy industry today

The long-term outlook for the uranium industry continues to be very positive, despite the uncertainty that exists today. Against the backdrop of the world’s growing need for safe, clean, reliable and large-scale sources of energy, nuclear energy continues to play a significant role in the global energy mix. 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.

And it is clear that this growth will require new sources of uranium supply at a time when secondary supplies are diminishing and current market conditions have resulted in deferrals and cancellations of several uranium projects. Current prices are insufficient to incent new production. The end of the Russian Highly Enriched Uranium (HEU) commercial agreement in 2013, removing 24 million pounds of annual supply from the market, highlights the need for increasing reliance on primary uranium supply in the future. The timing of this required supply may well be muted in the near term due to the extension of the over-supply situation, but it remains clear new supply will be required this decade. The development and execution of new uranium supply projects, as well as continued performance of existing supply, will also play a significant role in determining the timing and pace of market recovery.

MANAGEMENT’S DISCUSSION AND ANALYSIS    11

Industry prices

In 2013, the spot price declined from $44 (US) per pound to a low of about $34 (US) per pound. Utilities continue to be well covered under existing contracts. Given the current uncertainties in the market, we expect utilities and other market participants will continue to be opportunistic in their buying. We expect contracting over the next 12 months to remain somewhat discretionary.

	2013		2012		CHANGE
Uranium ($US/lb U3O8) 1
Average spot market price		38.17		48.40		(21	)%
Average long-term price		54.13		60.13		(10	)%
Fuel services ($US/kgU as UF6)1
Average spot market price
North America		9.60		7.99		20	%
Europe		10.07		8.56		18	%
Average long-term price
North America		16.50		16.75		(1	)%
Europe		17.17		17.25		—
Note: the industry does not publish UO2 prices.
Electricity ($/MWh)
Average Ontario electricity spot price		25		23		9	%

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

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World consumption and production

We estimate global uranium consumption in 2013 was about 167 million pounds and production was 156 million pounds.

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.

By 2023, we expect world uranium consumption to be about 240 million pounds per year, representing average annual growth of about 4%. These consumption estimates exclude strategic inventory building that we expect will occur in growth regions.

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

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

Contract volumes

The Ux estimate for global spot market sales in 2013 is about 50 million pounds, similar to previous years. Utilities and traders were responsible for the majority of the purchases, taking advantage of the lower spot prices to make opportunistic purchases.

At the start of 2013, we estimated long-term contracting volumes for the year to be between 75 million and 100 million pounds, though they ended the year at about 20 million pounds, a historical low. Neither buyers nor suppliers are under significant pressure to contract, and suppliers are likely hesitant to lock in meaningful volumes at current price levels. Long-term contracting volumes in 2014 will depend on market conditions.

MANAGEMENT’S DISCUSSION AND ANALYSIS    13

The long-term view

We remain confident in the long-term fundamentals of the nuclear industry, despite the near- to medium-term challenges. Our industry is driven by demand for energy, which continues to grow as a result of continued increases in world population and industrial development. The 2013 World Energy Outlook predicts that by 2035 electricity consumption will have grown by about 70% from current levels. Most of this energy will be used by developing (non-OECD) countries as their populations and standards of living increase.

New reactor outlook

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

In 2013, four reactors were connected to the grid (three in China and one in India), offset by the closures of four reactors in the United States. Construction commenced on 11 units during the year: four in the United States, four in China and one each in the UAE, South Korea and Belarus. Power uprates added about 645 megawatts of capacity to existing units.

Today, there are 433 operable reactors with a total generating capacity of 394 gigawatts. Over the next 10 years, we expect the number of reactors to grow to 526, with the startup of 144 units, offset by 51 closures. That represents generating capacity of about 514 gigawatts by 2023, which translates to an average annual growth of 3%.

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Of this growth, approximately 70 reactors with 75 gigawatts of generating capacity are under construction today. This is a significant rate of growth in new reactor construction. At the end of 2013, China continued to lead the growth with 29 reactors under construction. India, Russia, South Korea and the United States are also progressing in the expansion of their nuclear fleets. Of the 70 reactors under construction today, if startups occur as planned, 50 of those units (53 gigawatts) will be online over the next three years.

In the UK, the government is maintaining its commitment to nuclear energy as a source of emissions free energy. Critical milestones have been reached, allowing potential vendors to move forward with new build plans. In addition, several previously non-nuclear countries are moving ahead with their reactor construction programs or considering adding nuclear to their energy programs in the future. Construction work continues on two of four planned units in the UAE that will supply 5.6 gigawatts of nuclear capacity by 2020. Turkey is also moving forward with plans to build eight new reactors at two different sites. Belarus, Saudi Arabia, Vietnam, Bangladesh, Poland and Jordan are also moving forward with plans to proceed with nuclear power development.

DEMAND FOR URANIUM IS GROWING

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

SUPPLY UNCERTAINTY

While demand is expected to increase over the next decade, 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 estimate roughly two-thirds of global uranium supply over the next 10 years to come from existing primary production—mines that are currently in commercial operation—and about 15% to come from existing secondary supply sources. However, most secondary sources are finite and will not meet long-term needs. One of the largest sources of secondary supply is uranium derived from the Russian HEU commercial agreement, which came to an end in 2013, removing about 24 million pounds per year from the market. This volume is more than our current total annual production.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    15

Our 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. As a result of the longer-than-anticipated market uncertainty, we are adjusting our plans in line with this focus.

Market challenges have persisted since early 2011 and we expect they will continue for the near to medium term, depending on:

• the pace of Japanese reactor restarts

• how long it takes for excess supply to clear the market

• when long-term contracting resumes in meaningful quantities

• the development and execution of new uranium supply projects

• continued performance of existing supply

In this environment, a fixed production target is no longer appropriate; although we still have an extensive portfolio of assets from which we can increase our production capacity, we have decided the prudent action is to eliminate our previous 2018 supply target of 36 million pounds. This will allow us increased flexibility in order to deliver the best value through this period of uncertainty, while at the same time retaining the ability to benefit when more certainty returns to the market environment, as we expect it will. Today, our strategy is to profitably produce at a pace aligned with market signals to increase long-term shareholder value.

We plan to:

• carry out all of our business with a focus on safety, people and the environment

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

• ensure continued reliable, low-cost production at Inkai

• successfully bring on and ramp up production at Cigar Lake

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

• manage and allocate capital in a way that balances growing the long-term value of the business and returns to shareholders, while maintaining a strong balance sheet and our investment grade rating

Capital allocation

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

• create the greatest long-term value for our shareholders

• allow us to maintain our investment grade rating

• ensure we execute on our dividend policy

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

Reinvestment

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

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

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Return

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

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

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

Marketing Strategy

As with our corporate strategy and our approach to capital allocation, 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.

We sell uranium and fuel services directly to nuclear utilities around the world, as uranium concentrates, UO₂, UF₆, conversion services or fuel fabrication. Uranium is not traded in meaningful quantities on a commodity exchange. Utilities buy the majority of their uranium and fuel services products under long-term contracts with suppliers, and meet the rest of their needs on the spot market.

We have an extensive portfolio of long-term sales contracts which reflects the long-term, trusting relationships we have with our customers.

In addition, we are active in the spot market, buying and selling uranium 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.

OPTIMIZING REALIZED PRICE

We try to maximize our realized price by signing contracts with terms between five and 10 years (on average) that include mechanisms to protect us when market prices decline, and allow us to benefit when market prices go up.

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

40% FIXED-PRICE CONTRACTS, 60% MARKET-RELATED CONTRACTS

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 deliver 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS    17

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

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

CONTRACT PORTFOLIO STATUS

Currently, we are heavily committed under long-term uranium contracts through 2017, so we are being selective when considering new commitments. We have commitments to sell approximately 230 million pounds of U₃O₈ with 45 customers worldwide, and commitments to sell approximately 80 million kilograms as UF₆ conversion with 41 customers worldwide.

Customers – U₃O₈:

• 36% of volume to Americas (US, Canada, Latin America)

• 41% of volume to Asia

• 23% of volume to Europe

• five largest customers account for 50% of commitments

Customers – UF₆ conversion:

• 40% of volume to Americas (US, Canada, Latin America)

• 25% of volume to Asia

• 35% of volume to Europe

• five largest customers account for 54% of commitments

Managing our contract commitments and costs

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

• from our existing production

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

• from our existing inventory

Over the past 3 years, we have maintained sales in excess of 32 million pounds annually. Previously, we planned to maintain our sales volumes year over year using a combination of sources including production increases and normal course purchases, even once the Russian HEU commercial agreement came to an end. However, given the longer-than-expected period of market uncertainty, we have changed our plans in our continued pursuit to add value. Rather than maintaining sales at a fixed level, we will allow sales volume to vary depending on:

• the level of sales commitments in our long-term contract portfolio (the annual average sales commitments over the next five years is 30 million pounds, with commitment levels through 2016 higher than in 2017 and 2018)

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

• purchases under existing and/or new arrangements

• discretionary use of inventories

• market opportunities

PRODUCTION

To help us operate efficiently and cost-effectively, we manage operating costs and improve plant reliability by prudently investing in production infrastructure, new technology and business process improvements. Like all mining companies, our uranium segment is affected by the rising cost of inputs such as labour and fuel. In 2013, labour, production supplies and contracted services made up 92% of the production costs at our uranium mines. Labour (37%) was the largest component. Production supplies (28%) included fuels, reagents and other items. Contracted services (27%) included mining and maintenance contractors, air charters, security and ground freight.

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In 2014 and over the next few years, we will complete a number of capital projects at our various production facilities, including Cigar Lake. Upon completion, we will begin to depreciate the assets. This will increase the non-cash portion of our production costs and is expected to increase our unit cost of sales.

In addition, starting this year, we expect to begin to recognize the profits or losses related to Cigar Lake’s operating activities. All expenditures incurred prior to that time are expected to be capitalized as development costs. Depending on the actual timing of the rampup to the full production rate, we expect that the cash cost of material produced from Cigar Lake will initially be higher, which is also expected to increase our unit cost of sales.

Operating costs in our fuel services segment are mainly fixed. In 2013, labour accounted for about 54% of the total. The largest variable operating cost is for energy (natural gas and electricity), followed by zirconium and anhydrous hydrogen fluoride.

PURCHASES AND INVENTORY

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

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

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

OUTLOOK

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

We expect rising market prices for uranium will have a positive impact on our average realized price. In addition, as Cigar Lake reaches full production and the expansion at McArthur River/Key Lake is complete, our production will increase, which we expect will create more stability in the unit cost of sales for our uranium segment.

MANAGEMENT’S DISCUSSION AND ANALYSIS    19

Responsibility

Safety, environmental protection and supportive communities are high priorities during all stages of our activities, from exploration and development to operations, decommissioning and reclamation. We strive to be a leader in these areas through a strong safety culture, a focus on the environment, an engaged workforce, and informed and supportive communities. As a result, we are committed to the following principles:

• preventing injury, ill health and pollution

• complying with and moving beyond legal and other requirements

• keeping risks at levels as low as reasonably achievable

• ensuring quality of processes, products and services

Focus on long-term sustainability

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

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

You can find out more in our 2012 Sustainable Development report and 2013 data update on our website (cameco.com), or in our upcoming 2014 Sustainable Development report, which will be available in June.

We are committed to continual improvement in all aspects of our performance to ensure our operations continue to be safe, clean and reliable.

Safety

We have a long history of safety at our operations and across the organization as a result of a strong safety culture based around the following principles:

• safety is our first priority

• we are all accountable for safety

• safety is part of everything we do

• safety leadership is critical to us

• we are a learning organization

Over the past several years, we have focused on enhancing our safety culture, and our results in 2013 clearly show that we are achieving success. Many of our sites celebrated key safety milestones, including the Blind River Refinery (seven years without a lost-time injury (LTI)), Cameco Fuel Manufacturing Inc. (two years without an LTI), and the Port Hope conversion facility (one year without an LTI).

McArthur River, Key Lake, Rabbit Lake and Cigar Lake also delivered strong safety performance, with injury rates trending downward at each site. This is particularly noteworthy since all four facilities have seen increased levels of construction activity over the past several years.

A clean environment

We are committed to operating our business with the highest level of respect and care for the local and global environment. We strive to be a leader in environmental practices not only by complying with legal requirements, but by preventing pollution, conserving biodiversity, being properly prepared to respond to emergency situations, and by managing the environmental aspects of our business responsibly overall.

We continually refine our performance objectives and revisit the indicators we use to measure our progress, with the goal of continually improving.

Reducing our impact

We establish and implement risk-informed targets to reduce our potential effect on air, water and land, optimize our energy consumption, and manage waste. To ensure an effective approach to environmental performance, all of our operating sites have environmental management systems that are registered to the ISO-14001 standard.

• Water: We have employed water treatment technologies that have improved the quality of the treated water released from our Saskatchewan uranium mining and milling operations. For example, we have dramatically reduced molybdenum, uranium and selenium in effluent at these operations. We continue to look at how we can improve these treatment circuits and increase the efficiency of our water use to achieve even better results at all of our operations.

20     CAMECO CORPORATION

• Waste: We continue to work on projects to reduce waste, improve the reclamation process and manage waste rock more effectively. For example, at our Rabbit Lake operation, we completed reclamation of the B-Zone waste rock pile, which was a significant undertaking over the past several years.

• Air: We continue to revitalize our facilities to extend the lifespan of our operating sites. Although our emissions have always met all regulatory requirements, we have further improved air emissions by replacing some existing facilities. For example, replacement and upgrades to the sulphuric acid plants at Key Lake and Rabbit Lake have significantly reduced emissions of sulphur dioxide at those sites. Work to replace the calciner at Key Lake is also underway, which is expected to reduce emissions to air from the drying and packaging of the mill’s final product.

People

Our success over the past 25 years is largely a result of the knowledgeable, innovative, hard-working people that have been a part of the Cameco team. Going forward, it is important that we continue to have an engaged, qualified and diverse organization, capable of leading and implementing our strategies. Our challenge is to retain our current workforce and compete for the limited number of qualified people available. Our long-term people strategy includes identifying critical workforce segments and planning our workforce to meet this challenge.

Our approach is working. We were recognized in a number of ways for our employee programs in 2013: the Financial Post named us one of the Top 10 Best Companies to Work for in Canada for the fourth year in a row; Mediacorp named us one of Canada’s Top 100 Employers and also one of Canada’s Best Diversity Employers, both for the fourth year in a row; we were named one of Canada’s Top Employers for Young People by Mediacorp for the second year; and we were named a Top Employer for Canadians over 40 by Mediacorp. You can find out more about our awards on cameco.com.

Supportive communities

To maintain public support for our operations, we need the respect and support of communities, indigenous people, governments and regulators affected by our operations.

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

We build and sustain the trust of local communities by being a leader in corporate social responsibility (CSR). This was recognized by the Canadian Council of Aboriginal Business (CCAB) through its Progressive Aboriginal Relations program (PAR) when we were awarded our fourth consecutive Gold Level certification. Also in 2013, we were the proud recipient of the Prospector and Developer’s Association of Canada (PDAC) award in Environmental and Social Responsibility based on our long-term commitment to corporate social responsibility.

Through our CSR initiatives, we also educate, engage, employ and invest in the people in the regions where we operate.

For example, in northern Saskatchewan in 2013:

• just under 50% of the employees at our northern mines were local residents (747) and were paid more than $74 million in wages

• more than $450 million was paid to northern businesses, which provided 67% of services to our northern minesites. This is the second straight year we have surpassed the $450 million mark in our northern service spend.

• we made more than 70 community visits in northern Saskatchewan to discuss potential projects at our northern operations, and to provide career information to high school students and community members

MANAGEMENT’S DISCUSSION AND ANALYSIS    21

• we donated more than $1.1 million to northern and aboriginal initiatives for youth, health and wellness, education and literacy, and culture and recreation

• we supported high school and post-secondary students through scholarship, apprenticeship and summer student programs, work placements, and the Athabasca Education Awards

In an effort to formalize our relationship with local communities and guide future cooperation and the sharing of benefits from our operations, we have now negotiated two collaboration agreements with northern Saskatchewan communities. In a joint effort with AREVA, in 2013, we signed a collaboration agreement with the English River First Nation. This agreement, similar to the one we signed with the northern village of Pinehouse and the Kineepik Metis Local in 2012, sets out specific commitments by the mining companies with respect to workforce development, business development, community engagement, environmental stewardship and community investment. These agreements confirm the support of the First Nation people for our existing projects and operations, subject to our continued work to protect the health and safety of people and the environment.

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

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

22     CAMECO CORPORATION

Measuring our results

Our ability to build competitive advantage and deliver value is a function of our people, processes, assets and reputation.

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

• outstanding financial performance

• a safe, healthy and rewarding workplace

• a clean environment

• supportive communities

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

OUTSTANDING FINANCIAL PERFORMANCE
2013 OBJECTIVES	RESULTS
Earnings Measures • Achieve targeted adjusted net earnings and cash flow from operations (before working capital changes).	Exceeded • Adjusted net earnings1 were $445 million, 11% higher than our target. • Cash flow from operations (before working capital changes)1 was $669 million, 11% higher than our target.
Capital Management •     Execute capital projects within scope, on time and on budget.	Partially achieved • Our cost performance indicator for 2013 was 0.87 (over-budget), above the threshold however below the target of 1.0, due to cost overruns and necessary scope additions at Cigar Lake. • Our schedule performance indicator was below our threshold for 2013, resulting in a zero rating.
Cigar Lake •     Achieve production at Cigar Lake in 2013.	Not achieved •     In 2013, we made strong progress toward production, including jetting in waste, assembling a second jet boring system underground, and commissioning most of the other mine systems. We were also successful in obtaining the required construction and operating licence. However, production of the first packaged pounds was delayed as a result of additional work to ensure the safe, efficient operation of the mine and mill. In December, we began jet boring in ore, and have since completed the first cavity in ore.

¹  We use adjusted net earnings and cash flow from operations (before working capital changes) as a more meaningful way to compare our financial performance from period to period. These measures do not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS measure), and they should not be considered in isolation or as a substitute for financial information prepared in accordance with IFRS. Other companies may calculate these measures differently. Adjusted net earnings (non-IFRS measure) is our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting period. This measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period and adjusted for impairment charges, inventory write-downs, losses on exploration interests and income taxes on adjustments. Cash flow from operations (before working capital changes) of $669 million is cash provided by operations of $530 million with the changes in non-cash working capital of $139 million added back. Changes in non-cash working capital includes changes in accounts receivable, inventories, supplies and prepaid expenses, accounts payable and accrued liabilities, and certain other operating items, as further detailed in note 24 to our audited 2013 financial statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS    23

SAFE, HEALTHY AND REWARDING WORKPLACE
2013 OBJECTIVES	RESULTS
•     Strive for no lost-time injuries (LTI) at all Cameco-operated sites and, at a minimum, maintain a long-term downward trend in combined employee and contractor injury frequency and severity, and radiation doses.	Exceeded •     Overall safety performance was strong in 20131. Injury rates trended downward across the company and were better than expected. Average radiation doses remained low and stable. In the past two years, we have met our targets for safety performance.
•     Attract and retain the employees needed to support operations and growth.	Achieved •     We were listed as both a Top 100 Employer (for the fifth year in a row) and one of the Financial Post’s 10 Best Companies to Work For, in addition to receiving awards for being among Saskatchewan’s Top 10 Employers, Canada’s Best Diversity Employers, Top Employer for Canadians Over 40, and a Top Employer for Young People. •     Our 2013 turnover rate of 8.3% (excluding the impact of restructuring) was lower than our target of 9%. •     The expected turnover rate for new hires within the first year of employment was slightly higher than expected at 12.7%.

¹  Measured against the Occupational Safety and Health Administration (OSHA) safety metrics, total recordable incident rate (TRIR) and days away, restricted or transferred (DART), adopted by the company to continue to drive improvements in safety performance. TRIR is a measure of the rate of “recordable” workplace injuries. Examples of “recordable injuries” are a medical treatment (other than first aid), restricted work, lost time and other specific injuries such as 10 decibel hearing loss, loss of consciousness and broken bone. DART is a measure of the rate of workplace injuries and illnesses that require employees to miss work, perform restricted work activities or transfer to another job within a calendar year.

CLEAN ENVIRONMENT
2013 OBJECTIVES	RESULTS
•     Do not incur an incident that results in moderate or significant environmental impacts or remediation costs of greater than or equal to $1M or which has reasonable potential to result in significant negative impact on the company’s reputation. Achieve a decreasing trend for environmental incidents, measured as less than the long-term average.	Exceeded • There were no significant environmental incidents in 2013, and our reportable environmental incidents were significantly lower than our long-term average of 38, with only 22 over the course of the year.

SUPPORTIVE COMMUNITIES
2013 OBJECTIVES	RESULTS
•     Increase employment of residents of Saskatchewan’s north (RSN) by 2% (15 net additions) over 2012. •     Support northern business development opportunities by procuring at least 75% of northern services from northern Saskatchewan vendors.	Not achieved •     Overall RSN employment decreased seven positions from 2012 to 747 positions. However, we were successful in adding 18 RSN employees at Cigar Lake, and maintained a 50% RSN workforce overall at the northern sites. •     Only 67% of northern services were procured from northern Saskatchewan vendors. We did not achieve our target due to disproportionate growth in overall spend, cost efficiencies and a temporary increase in expenditures, largely growth capital at Cigar Lake which required specialized services that were not available from northern Saskatchewan vendors. Over the past few years, overall spend has grown faster than the growth in capacity of northern vendors. Despite not achieving our targeted ratio, the nominal business volume with northern Saskatchewan vendors has more than doubled since 2009.

24     CAMECO CORPORATION

2014 objectives

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

OUTSTANDING FINANCIAL PERFORMANCE

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

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

• Achieve production at Cigar Lake in 2014, and advance other activities needed to achieve medium and long-term growth objectives.

SAFE, HEALTHY AND REWARDING WORKPLACE

• Improve workplace safety performance at all sites.

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

CLEAN ENVIRONMENT

• Improve environmental performance at all sites.

SUPPORTIVE COMMUNITIES

• Build and sustain strong stakeholder support for our activities.

MANAGEMENT’S DISCUSSION AND ANALYSIS    25

Financial results

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

27	2013 CONSOLIDATED FINANCIAL RESULTS
35	OUTLOOK FOR 2014
35	LIQUIDITY AND CAPITAL RESOURCES
40	BALANCE SHEET
41	2013 FINANCIAL RESULTS BY SEGMENT
41	URANIUM
44	FUEL SERVICES
44	NUKEM
46	ELECTRICITY
50	FOURTH QUARTER RESULTS BY SEGMENT
50	URANIUM
52	FUEL SERVICES
52	NUKEM
53	ELECTRICITY

26     CAMECO CORPORATION

2013 consolidated financial results

Starting in the first quarter of 2013, IFRS 11 – Joint Arrangements requires that we account for our interest in BPLP using equity accounting. Our results for 2012 throughout this MD&A have been revised for comparative purposes; however, our results for 2011 have not been revised. See New standards and interpretations not yet adopted on page 91 for more information.

HIGHLIGHTS DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED)	2013		2012		20111		CHANGE FROM 2012 TO 2013
Revenue		2,439		1,891		2,384		29	%
Gross profit		607		540		776		12	%
Net earnings attributable to equity holders		318		253		450		26	%
$ per common share (basic)		0.81		0.64		1.14		27	%
$ per common share (diluted)		0.81		0.64		1.14		27	%
Adjusted net earnings (non-IFRS, see page 28)		445		434		509		3	%
$ per common share (adjusted and diluted)		1.12		1.10		1.29		2	%
Cash provided by operations (after working capital changes)		530		579		745		(8	)%

¹  Our 2011 results have not been revised; at that time, we accounted for BPLP using proportional consolidation.

Net earnings

Our net earnings attributed to equity holders (net earnings) were $318 million ($0.81 per share diluted) compared to $253 million ($0.64 per share diluted) in 2012, mainly due to:

• the impact of a one-time $168 million write-down of our investment in the Kintyre project in 2012

• higher earnings from our fuel services business as a result of an increase in sales volumes and realized prices

• lower exploration expenditures due to a decreased activity at our Kintyre project in Australia

• higher tax recoveries due to a decline in pre-tax earnings in Canada. See Income Taxes on page 31 for details.

partially offset by:

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

• a $70 million write-down of our Talvivaara asset due to their weakened financial position and pending corporate restructuring

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

THREE-YEAR TREND

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

In 2012, our net earnings were $197 million lower than in 2011 primarily due to the write-down of our investment in the Kintyre project, and lower earnings from our uranium business as a result of lower realized prices and an increase in the cost of product sold, which was partially offset by higher earnings from our electricity business and lower taxes in that year.

Impairment charge on non-producing assets

During the fourth quarter of 2013, we recognized a $70 million impairment charge relating to our agreement with Talvivaara Mining Company Plc. to purchase uranium produced at the Sotkamo nickel-zinc mine in Finland. The impairment charge represents the full amount of our investment, which was used to cover construction costs, with the amount to be repaid through deliveries of uranium concentrate. The amount of the charge was determined as the excess of the carrying value over the fair value, less costs to sell. Due to Talvivaara’s weak financial position and application to the Finnish government to undergo a corporate restructuring, as an unsecured creditor, we determined the fair value less costs to sell to be nil, and as such, recognized an impairment charge for the full amount of the asset.

MANAGEMENT’S DISCUSSION AND ANALYSIS    27

Non-IFRS measures

ADJUSTED NET EARNINGS

Adjusted net earnings is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS measure). We use this measure as a more meaningful way to compare our financial performance from period to period. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance. Adjusted net earnings is our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting period. The adjusted earnings measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period, and adjusted for impairment charges on non-producing properties, NUKEM inventory write-down, loss on exploration properties, and income taxes on adjustments.

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

To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the years ended 2013, 2012 and 2011, as reported in our financial statements.

($ MILLIONS)	2013			2012			2011
Net earnings attributable to equity holders		318			253			450
Adjustments
Adjustments on derivatives1 (pre-tax)		56			17			80
Impairment charge on non-producing property		70			168			—
NUKEM inventory write-down		14			—			—
Loss on exploration properties		15			—			—
Income taxes on adjustments		(28	)		(4	)		(21	)
Adjusted net earnings		445			434			509

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

28     CAMECO CORPORATION

The table below shows what contributed to the change in adjusted net earnings for 2013.

($ MILLIONS)
Adjusted net earnings – 2012		434
Change in gross profit by segment (we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits)
Uranium	Lower sales volume	(2	)
	Higher realized prices ($US)	21
	Foreign exchange impact on realized prices	48
	Higher costs	(30	)
	Hedging benefits	(66	)
	change – uranium	(29	)
Fuel services	Higher sales volume	3
	Higher realized prices ($Cdn)	7
	Lower costs	1
	Hedging benefits	(8	)
	change – fuel services	3
NUKEM	Gross profit, net of pretax inventory adjustment	33
	change – NUKEM	33
Other changes
Lower earnings from equity investment in BPLP		(48	)
Contract termination charge		30
Higher administration expenditures		(4	)
Lower exploration expenditures		24
Loss on equity accounted investments		(5	)
Lower income taxes		15
Other		(8	)
Adjusted net earnings – 2013		445

THREE-YEAR TREND

Our adjusted net earnings declined from 2011 to 2012, but increased in 2013.

The 15% decrease from 2011 to 2012 resulted from:

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

• higher charges for administration and exploration

partially offset by:

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

• lower income taxes

The 3% increase from 2012 to 2013 resulted from:

• addition of gross profit from NUKEM

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

• lower income taxes

partially offset by:

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    29

Revenue

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

($ MILLIONS)
Revenue – 2012	1,891
Uranium
Lower sales volume	(7	)
Higher realized prices ($Cdn)	68
Fuel services
Higher sales volume	21
Higher realized prices ($Cdn)	7
NUKEM	465
Other	(6	)
Revenue – 2013	2,439

See 2013 Financial results by segment on page 41 for more detailed discussion.

THREE-YEAR TREND

In 2012, revenue declined by 21% compared to 2011 mainly due to the exclusion of revenue from our interest in BPLP in 2012. For 2012, a revision was made to account for BPLP using equity accounting, however the 2011 results have not been revised. Further contributing to the decline was a lower realized price for uranium, which was $1.46 per pound lower than the average realized price of $49.18 per pound in 2011.

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

Average realized prices

			2013		2012		2011		CHANGE FROM 2012 TO 2013
Uranium1	$	US/lb		48.35		47.72		49.17		1	%
	$	Cdn/lb		49.81		47.72		49.18		4	%
Fuel services	$	Cdn/kgU		18.12		17.75		16.71		2	%
Electricity	$	Cdn/MWh		54		55		54		(2	)%

¹  Average realized foreign exchange rate ($US/$Cdn): 2013 – $1.03, 2012 – $1.00, and 2011 – $1.00

Outlook for 2014

We expect consolidated revenue to be up to 5% higher in 2014 due to an increase in realized prices in our uranium business.

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns and, therefore, our sales volumes and revenue, can vary significantly. We expect that uranium deliveries in the first quarter of 2014 will be slightly higher than the first quarter of 2013, with about 20% of the year’s deliveries scheduled for the first three months. We expect uranium deliveries for the balance of 2014 to be more heavily weighted (~60%) to the second half of the year. However, not all delivery notices have been received to date, which could alter the delivery pattern. Typically, we receive notices six months in advance of the requested delivery date.

Corporate expenses

RESTRUCTURING

As a result of our restructuring activities, we saw improvements in our direct administration and exploration costs during the year. The benefit of these savings has been partially offset by the one-time costs associated with restructuring; however, we have achieved efficiencies we expect will be sustainable over time.

30     CAMECO CORPORATION

ADMINISTRATION

($ MILLIONS)	2013		2012		CHANGE
Direct administration		160		163		(2	)%
Restructuring		5		—		—
Stock-based compensation		20		18		11	%
Total administration		185		181		2	%

Direct administration costs in 2013 were $3 million lower than in 2012. The decrease in the year reflects the effects from our restructuring activities. These were partially offset by:

• the addition of NUKEM’s administration ($15 million)

• advisory fees with respect to the NUKEM acquisition ($3 million)

We recorded $20 million in stock-based compensation expenses this year under our stock option, deferred share unit, performance share unit and phantom stock option plans, compared to $18 million in 2012. See note 25 to the financial statements.

Outlook for 2014

We expect administration costs (not including stock-based compensation) to be relatively stable (0% to 5% higher) compared to 2013, as restructuring benefits offset inflation.

EXPLORATION

In 2013, uranium exploration expenses were $73 million, a decrease of $24 million compared to 2012 due largely to decreased activity at our Kintyre project in Australia. Our exploration efforts in 2013 focused on Canada and Australia.

Outlook for 2014

We expect exploration expenses to be about 35% to 40% lower than they were in 2013 due to:

• decreased activities in Australia

• a general reorganization of our global exploration portfolio that has allowed us to focus on our core projects in Saskatchewan

FINANCE COSTS

Finance costs were $62 million compared to $68 million in 2012. The decrease from last year largely reflects lower foreign exchange expenses partially offset by higher interest on long-term debt and higher reclamation charges. See note 20 to the financial statements.

FINANCE INCOME

Finance income was $7 million compared to $14 million in 2012 due to lower levels of short-term investments in 2013.

GAINS AND LOSSES ON DERIVATIVES

In 2013, we recorded $62 million in losses on our derivatives compared to gains of $41 million in 2012. The losses reflect the weakening of the Canadian dollar compared to the US dollar in 2013. See note 27 to the financial statements.

INCOME TAXES

We recorded an income tax recovery of $90 million in 2013 compared to $51 million in 2012. The increase was primarily due to a change in the distribution of earnings between jurisdictions compared to 2012. In 2013, we recorded losses of $603 million in Canada compared to $337 million in 2012, whereas earnings in foreign jurisdictions increased to $830 million from $538 million. The tax rate in Canada is higher than the average of the rates in the foreign jurisdictions in which our subsidiaries operate. See note 22 to the financial statements.

MANAGEMENT’S DISCUSSION AND ANALYSIS    31

On an adjusted earnings basis, we recognized a tax recovery of $61 million in 2013 compared to $46 million in 2012. The increase was related to the items noted above. Our effective tax rate was a recovery of 16% in 2013 compared to 12% in 2012. The table below presents our adjusted earnings and adjusted income tax expenses attributable to Canadian and foreign jurisdictions.

($ MILLIONS)	2013			2012
Pre-tax adjusted earnings1
Canada2		(466	)		(320	)
Foreign2		849			706
Total pre-tax adjusted earnings		383			386
Adjusted income taxes1
Canada2		(94	)		(74	)
Foreign		33			28
Adjusted income tax expense (recovery)		(61	)		(46	)
Effective tax rate		(16	)%		(12	)%

¹  Pre-tax adjusted earnings and adjusted income taxes are non-IFRS measures.

² Our IFRS-based measures have been adjusted by the amounts reflected in the table in adjusted net earnings (non-IFRS measure on page 28).

CRA DISCLOSURE

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

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

32     CAMECO CORPORATION

• 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.

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 2 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.

Assumptions

• CRA will reassess us for the years 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

MANAGEMENT’S DISCUSSION AND ANALYSIS    33

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

Outlook for 2014

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

On an adjusted net earnings basis, we expect a tax recovery of 30% to 35% in 2014 from our uranium, fuel services and NUKEM segments, as taxable income in Canada is expected to decline. Subject to our success in the litigation with CRA, we expect our tax recovery to continue in accordance with the 2014 outlook until the contractual arrangements noted above expire in 2016. As these arrangements expire and are replaced by new contracts that reflect the uranium market at the time of signing, our tax expense is expected to rise over time.

FOREIGN EXCHANGE

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

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

At December 31, 2013:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.06 (Cdn), up from $1.00 (US) for $0.99 (Cdn) at December 31, 2012. The exchange rate averaged $1.00 (US) for $1.03 (Cdn) over the year.

• Our effective exchange rate for the year was about $1.00 (US) for $1.03 (Cdn), up from $1.00 (US) for $1.00 (Cdn) in 2012.

• We had foreign currency forward contracts of $1.6 billion (US), EUR 63 million, AUD 4 million at December 31, 2013. The US currency contracts had an average exchange rate of $1.00 (US) for $1.05 (Cdn).

• The mark-to-market loss on all foreign exchange contracts was $27 million compared to a $15 million gain at December 31, 2012.

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2013, all counterparties to foreign exchange hedging contracts had a Standard & Poor’s (S&P) credit rating of A or better.

SENSITIVITY ANALYSIS

At December 31, 2013, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2014 net earnings by about $5 million (Cdn), with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact. This sensitivity is based on an exchange rate of $1.00 (US) for $1.00 (Cdn).

34     CAMECO CORPORATION

Outlook for 2014

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

Our outlook for 2014 reflects the expenditures necessary to help us achieve our strategy. We do not provide an outlook for the items in the table that are marked with a dash.

See 2013 Financial results by segment on page 41 for details.

2014 FINANCIAL OUTLOOK

Subject to closing, we sold our interest in BPLP and related entities effective December 31, 2013, and we will no longer provide an outlook for the electricity segment.

	CONSOLIDATED	URANIUM	FUEL SERVICES	NUKEM
Production	—	23.8 to 24.3 million lbs	13 to 14 million kgU	—
Sales volume	—	31 to 33 million lbs	Decrease 5% to 10%	9 to 11 million lbs U3O8
Revenue compared to 2013	Increase 0% to 5%	Increase 0% to 5%1	Decrease 5% to 10%	Increase 0% to 5%
Average unit cost of sales (including D&A)	—	Increase 0% to 5%2	Increase 0% to 5%	Increase 0% to 5%
Direct administration costs compared to 20133	Increase 0% to 5%	—	—	Increase 0% to 5%
Exploration costs compared to 2013	—	Decrease 35% to 40%	—	—
Tax rate	Recovery of 30% to 35%	—	—	Expense of 30% to 35%
Capital expenditures	$495 million	—	—	—

¹  Based on a uranium spot price of $35.50 (US) per pound (the Ux spot price as of February 3, 2014), a long-term price indicator of $50.00 (US) per pound (the Ux long-term indicator on January 27, 2014) and an exchange rate of $1.00 (US) for $1.03 (Cdn).

²  This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we make discretionary purchases in 2014 then we expect the overall unit cost of sales to increase further.

³  Direct administration costs do not include stock-based compensation expenses. See page 31 for more information.

SENSITIVITY ANALYSIS

For 2014, a change of $5 (US) per pound in each of the Ux spot price ($35.50 (US) per pound on February 3, 2014) and the Ux long-term price indicator ($50.00 (US) per pound on January 27, 2014) would change revenue by $67 million and net earnings by $42 million.

Liquidity and capital resources

At the end of 2013, we had cash and short-term investments of $229 million in a mix of short-term deposits and treasury bills, while our total debt amounted to $1.4 billion.

We have large, creditworthy customers that continue to need uranium even during weak economic conditions, and we expect the uranium contract portfolio we have built to provide a solid revenue stream for years to come.

We expect to invest in our production capacity at a pace aligned with market signals. We have a number of alternatives to fund our investments including using our current cash balances, drawing on our existing credit facilities, entering new credit facilities, using our operating cash flow, and raising additional capital through debt or equity financings. We are always considering our financing options so that we can take advantage of favourable market conditions when they arise. However, we expect our existing cash balances and operating cash flows will meet our anticipated 2014 capital requirements without the need for significant additional funding.

MANAGEMENT’S DISCUSSION AND ANALYSIS    35

FINANCIAL CONDITION

	2013			2012
Cash position ($ millions) (cash, cash equivalents, short-term investments, less bank overdraft)		188			799
Cash provided by operations ($ millions) (net cash flow generated by our operating activities after changes in working capital)		530			579
Cash provided by operations/net debt (net debt is total consolidated debt, less cash position)		46	%		103	%
Net debt/total capitalization (total capitalization is total long-term debt and equity)		17	%		9	%

CREDIT RATINGS

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

Third-party ratings for our commercial paper and senior debt as of December 31, 2013:

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

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

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

Liquidity

($ MILLIONS)	2013			2012
Cash, cash equivalents and short-term investments at beginning of year		799			1,202
Cash from operations		530			579
Investment activities
Additions to property, plant and equipment and acquisitions		(898	)		(1,248	)
Other investing activities		(6	)		(23	)
Financing activities
Change in debt		(18	)		485
Interest paid		(66	)		(44	)
Issue of shares		2			7
Dividends		(158	)		(158	)
Exchange rate on changes on foreign currency cash balances		3			(1	)
Cash, cash equivalents and short term investments, less bank overdraft at end of year		188			799

Cash from operations

Cash from operations was 8% lower than in 2012 mainly due to working capital requirements largely offset by higher profits in the uranium business and the addition of NUKEM. Not including working capital requirements, our operating cash flows in the year were up $103 million. See note 24 to the financial statements.

Investing activities

Cash used in investing includes acquisitions and capital spending.

ACQUISITIONS AND DIVESTITURES

On January 9, 2013 we completed the acquisition of NUKEM by paying a total of $140 million (US) and assuming its net debt of $111 million (US). In the third quarter of 2013, as part of our strategy to focus on projects that provide the most certainty in the near term, we divested our interests in Argentina and Peru and recorded a loss of $15 million.

36     CAMECO CORPORATION

On January 30, 2014, we signed an agreement with BPC Generation Infrastructure Trust to sell our 31.6% limited partnership interest in BPLP and related entities for $450 million. The effective date for the sale is December 31, 2013. We expect to realize an after tax gain of approximately $129 million on this divestiture.

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 approvals.

CAPITAL SPENDING

We classify capital spending as sustaining, capacity replacement or growth. As a mining company, sustaining capital is the money we spend to keep our facilities running in their present state, which would follow a gradually decreasing production curve, while capacity replacement capital is spent to maintain current production levels at those operations. Growth capital is money we invest to generate incremental production, and for business development.

CAMECO’S SHARE ($ MILLIONS)	2013 PLAN			2013 ACTUAL		2014 PLAN
Sustaining capital
McArthur River/Key Lake		55			64		30
Cigar Lake		—			—		15
Rabbit Lake		70			50		40
US ISR		5			5		5
Inkai		7			1		5
Fuel services		10			8		10
Other		23			9		10
Total sustaining capital		170			137		115
Capacity replacement capital
McArthur River/Key Lake		75			73		60
Cigar Lake		—			—		25
Rabbit Lake		5			3		15
US ISR		30			22		20
Inkai		20			16		15
Total capacity replacement capital		130			114		135
Growth capital
McArthur River/Key Lake		55			29		75
US ISR		30			33		10
Millennium		5			5		5
Inkai		21			9		5
Cigar Lake		260			284		145
Fuel Services		4			2		5
Total growth capital		375			362		245
Talvivaara		10			10		—
Total uranium & fuel services		685	1		623		495
Electricity (our 31.6% share of BPLP)		80			75		—

¹  We updated our 2013 capital cost estimate in the Q2 MD&A to $685 million.

Capital expenditures were 9% below our 2013 plan, mainly due to variances at Rabbit Lake, Inkai, and McArthur River/Key Lake caused by a change in the timing of expenditures.

MANAGEMENT’S DISCUSSION AND ANALYSIS    37

OUTLOOK FOR INVESTING ACTIVITIES

(CAMECO’S SHARE IN $ MILLIONS)	2015 PLAN		2016 PLAN
Total uranium & fuel services		400-450		500-550
Sustaining capital		160-175		220-240
Capacity replacement capital		150-170		165-175
Growth capital		90-105		115-135

We expect total capital expenditures for uranium and fuel services to decrease by about 21% in 2014.

Major sustaining, capacity replacement and growth expenditures in 2014 include:

• McArthur River/Key Lake – At McArthur River, the largest project is the upgrade of the electrical infrastructure at about $56 million. Mine development is also planned at about $105 million. Other projects include expansion of freeze capacity and other site facility and equipment purchases. At Key Lake, projects will be undertaken to finish work on the calciner and upgrade site electrical services

• US in situ recovery (ISR) – Continued work on the development of the North Butte mine represents a large portion of our wellfield construction expenditures in the US. Well installation at other mine units is also significant.

• Rabbit Lake – At Eagle Point, the largest component is mine development at about $24 million, along with mine equipment upgrades and purchases. Work on various mill facility and equipment replacements will also continue.

• Cigar Lake – Underground mine development makes up the largest portion of capital at the Cigar Lake site, at about $30 million. Completion of various mine facilities will continue into 2014, as well as the purchase of mine equipment in order to ramp up to full production. Our share of the costs to modify the McClean Lake mill are expected to be about $100 million in 2014.

We previously estimated capital costs on our brownfield expansions and development projects to be between $135 and $190 million per year for the next three years. We now estimate capital costs for our brownfield expansions and development projects to be about $245 million in 2014 due to the delayed startup of Cigar Lake production and additional costs at the McClean Lake mill. Growth capital is then expected to be between $90 and $135 million per year for 2015 and 2016.

The removal of our fixed production target allows us to better align our capital spending with market signals. As the market begins to signal new production is needed, we plan to increase our capital expenditures to allow us to be among the first to respond to the growth we see coming.

This information regarding currently expected capital expenditures for future periods is forward-looking information, and is based upon the assumptions and subject to the material risks discussed on pages 2 and 3. Our actual capital expenditures for future periods may be significantly different.

Financing activities

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

LONG-TERM CONTRACTUAL OBLIGATIONS

DECEMBER 31 ($ MILLIONS)	2014		2015 AND 2016		2017 AND 2018		2019 AND BEYOND		TOTAL
Long-term debt		—		300		—		1,000		1,300
Interest on long-term debt		63		111		97		210		481
Provision for reclamation		18		71		65		669		823
Provision for waste disposal		2		4		5		7		18
Other liabilities		—		—		—		46		46
Total		83		486		167		1,932		2,668

38     CAMECO CORPORATION

We have unsecured lines of credit of about $2.2 billion, which include the following:

• A $1.25 billion unsecured revolving credit facility that matures November 1, 2018. Each year on the anniversary date, and upon mutual agreement, the facility can be extended for an additional year. In addition to borrowing directly from this facility, we can use up to $100 million of it to issue letters of credit and we may use it to provide liquidity for our commercial paper program, as necessary. We may increase the revolving credit facility above $1.25 billion, by increments of no less than $50 million, up to a total of $1.75 billion. The facility ranks equally with all of our other senior debt. At December 31, 2013, there were no amounts outstanding under this facility.

• Approximately $799 million in short-term borrowing and letters of credit provided by various financial institutions. We use these facilities mainly to provide financial assurance for future decommissioning and reclamation of our operating sites, and as overdraft protection. At December 31, 2013, we had approximately $791 million outstanding in letters of credit.

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

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

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

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

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

We have issued a $73 million (US) promissory note to GLE to support future development of its business. As of December 31, 2013, GLE requested drawings of $63 million (US) in principal and $8 million (US) in interest. The remaining balance of $10 million (US) was drawn on February 4, 2014.

DEBT COVENANTS

Our revolving credit facility includes the following financial covenants:

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

• other customary covenants and events of default

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

Not complying with any of these covenants could result in accelerated payment and termination of our revolving credit facility. At December 31, 2013, we complied with all covenants, and we expect to continue to comply in 2014.

Off-balance sheet arrangements

We had two kinds of off-balance sheet arrangements at the end of 2013:

• purchase commitments

• financial assurances

PURCHASE COMMITMENTS

DECEMBER 31 ($ MILLIONS)	2014		2015 AND 2016		2017 AND 2018		2019 AND BEYOND		TOTAL
Purchase commitments1		352		583		109		164		1,208

¹  Denominated in US dollars, converted to Canadian dollars as of December 31, 2013 at the rate of $1.06.

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

At the end of 2013, we had committed to $1.2 billion (Cdn) for the following:

• Approximately 21 million pounds of U₃O₈ equivalent from 2014 to 2022.

• Approximately 15 million kgU as UF₆ in conversion services from 2014 to 2016 primarily under our agreements with Springfields Fuels Ltd. (SFL).

• Over 1.1 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-western supplier.

MANAGEMENT’S DISCUSSION AND ANALYSIS    39

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

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

FINANCIAL ASSURANCES

DECEMBER 31 ($ MILLIONS)	2013		2012		CHANGE
Standby letters of credit		791		672		18	%
BPLP guarantees		58		59		(2	)%
Total		849		731		16	%

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

Our total commitment for financial guarantees on behalf of BPLP was an estimated $58 million at the end of the year. See note 12 to the financial statements.

Balance sheet

DECEMBER 31 ($ MILLIONS EXCEPT PER SHARE AMOUNTS)	2013		2012		20111		CHANGE FROM 2012 TO 2013
Inventory		913		564		494		62	%
Total assets		8,039		7,431		7,616		8	%
Long-term financial liabilities		1,915		1,903		1,736		1	%
Dividends per common share		0.40		0.40		0.40		—

¹  Our 2011 results have not been revised; at that time, we accounted for BPLP using proportional consolidation.

Total product inventories increased by 62% to $913 million this year mainly due to the addition of NUKEM inventories. Higher levels of inventory for uranium and fuel services, where the quantities sold were lower than the quantities produced and purchased for the year also affected inventory levels. The average cost of uranium was higher as the cost of material produced and purchased during the year was higher than the average cost of inventory at the beginning of the year. In addition, the weakening of the Canadian dollar increased the Canadian carrying value of inventory in our foreign subsidiaries. At December 31, 2013, our average cost for uranium was $29.15 per pound, up from $27.35 per pound at December 31, 2012. In 2012, total product inventories increased by 14% due to higher levels of uranium, where the quantities sold were lower than the quantities produced and purchased for the year.

At the end of 2013, our total assets amounted to $8.0 billion, an increase of $0.6 billion compared to 2012 due primarily to the acquisition of NUKEM in the year. In 2012, the total asset balance decreased by $0.2 billion compared to 2011 primarily due to the change in our accounting treatment for BPLP, which was revised for 2012 and not revised for 2011, largely offset by acquisitions of uranium properties in the year.

The major components of long-term financial liabilities are long-term debt, the provision for reclamation and financial derivatives. In 2013, our balance did not change significantly. In 2012, our balance increased by $0.2 billion.

40     CAMECO CORPORATION

2013 financial results by segment

Uranium

HIGHLIGHTS	2013		2012		CHANGE
Production volume (million lbs)		23.6		21.9		8	%
Sales volume (million lbs)		32.8		32.9		—
Average spot price ($US/lb)		38.17		48.40		(21	)%
Average long-term price ($US/lb)		54.13		60.13		(10	)%
Average realized price
($US/lb)		48.35		47.72		1	%
($Cdn/lb)		49.81		47.72		4	%
Average unit cost of sales ($Cdn/lb) (including D&A)		33.01		32.09		3	%
Revenue ($ millions)		1,633		1,571		4	%
Gross profit ($ millions)		550		514		7	%
Gross profit (%)		34		33		3	%

Production volumes in 2013 were 8% higher than 2012 due to higher production from nearly every site compared to 2012. See Uranium – production overview on page 57 for more information.

Uranium revenues this year were up 4% compared to 2012, due to an increase of 4% in the Canadian dollar average realized price. Although the spot and term prices were lower than 2012, our average realized prices this year were higher mainly due to the mix of contracts, higher US dollar prices under fixed price contracts and the effect of foreign exchange. The realized foreign exchange rate was $1.03 compared to $1.00 in 2012. The spot price for uranium averaged $38.17 (US) per pound in 2013, a decline of 21% compared to the 2012 average price of $48.40 (US) per pound. Total cost of sales (including D&A) remained stable compared to 2012 at $1.1 billion as an increase in the average unit cost of sales was offset by slightly lower sales volumes.

The net effect was a $36 million increase in gross profit for the year.

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

($CDN/LB)	2013		2012		CHANGE
Produced
Cash cost		18.37		19.95		(8	)%
Non-cash cost		9.46		8.13		16	%
Total production cost		27.83		28.08		(1	)%
Quantity produced (million lbs)		23.6		21.9		8	%
Purchased
Cash cost		27.95		28.50		(2	)%
Quantity purchased (million lbs)		13.2		11.2		18	%
Totals
Produced and purchased costs		27.87		28.22		(1	)%
Quantities produced and purchased (million lbs)		36.8		33.1		11	%

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

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    41

To facilitate a better understanding of these measures, the table below presents a reconciliation of these measures to our unit cost of sales for the years ended 2013 and 2012 as reported in our financial statements.

CASH AND TOTAL COST PER POUND RECONCILIATION

($ MILLIONS)	2013			2012
Cost of product sold		869.1			883.7
Add / (subtract)
Royalties		(90.8	)		(116.0	)
Standby charges		(37.4	)		(28.6	)
Other selling costs		(1.4	)		(6.2	)
Change in inventories		63.1			23.1
Cash operating costs (a)		802.6			756.0
Add / (subtract)
Depreciation and amortization		212.9			172.9
Change in inventories		10.1			5.2
Total operating costs (b)		1,025.6			934.1
Uranium produced and purchased (millions lbs) (c)		36.8			33.1
Cash costs per pound (a ÷ c)		21.81			22.84
Total costs per pound (b ÷ c)		27.87			28.22

Outlook for 2014

We expect to produce 23.8 million to 24.3 million pounds in 2014 and have commitments under long-term contracts to purchase approximately 2 million pounds.

Based on the contracts we have in place, we expect to deliver between 31 million and 33 million pounds of U₃O₈ in 2014. We expect the unit cost of sales to be up to 5% higher than in 2013, primarily due to higher costs for produced material. In 2014, we will complete a number of capital projects at our various production facilities, including Cigar Lake. Upon completion, we will begin to depreciate the assets, which will increase the non-cash portion of our production costs. In addition, until Cigar Lake ramps up to full production, the cash cost of material produced from the mine will initially be higher. If we make additional discretionary purchases in 2014, then we expect the overall unit cost of sales to increase further.

Based on current spot prices, revenue should be up to 5% higher than it was in 2013 as a result of an expected increase in the realized price.

PRICE SENSITIVITY ANALYSIS: URANIUM

The table and graph below are not forecasts of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table and graph. They are designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2013 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on December 31, 2013, and none of the assumptions we list below change.

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

42     CAMECO CORPORATION

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)

SPOT PRICES ($US/LB U3O8)	$20		$40		$60		$80		$100		$120		$140
2014		45		48		55		62		69		76		81
2015		41		46		55		65		75		84		93
2016		42		47		57		68		78		88		96
2017		42		47		57		67		77		86		93
2018		43		49		58		68		78		86		93

The table and graph illustrate the mix of long-term contracts in our December 31, 2013 portfolio, and are consistent with our marketing strategy. Both have been updated to reflect deliveries made and contracts entered into up to December 31, 2013.

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

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

Sales

• sales volumes on average of 30 million pounds per year, with commitment levels through 2016 higher than in 2017 and 2018

Deliveries

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

• we defer a portion of deliveries under existing contracts for 2014

Annual inflation

• is 1.5% in Canada and 2% in the US

Prices

• the average long-term price indicator is the same as the average spot price for the entire year (a simplified approach for this purpose only). Since 1996, the long-term price indicator has averaged 17% higher than the spot price. This differential has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table and graph will be higher.

ROYALTIES

On January 3, 2014, the government of Saskatchewan released regulations to implement the changes to the Saskatchewan uranium royalty system originally announced in the 2013 provincial budget.

The government has changed tiered royalties from a revenue-based system to a modified profit-based system, retroactive to January 1, 2013. Under the new system, a 10% royalty will be charged on profit up to and including $22/kg U₃O₈ ($9.98/lb), and a 15% royalty on profit in excess of $22/kg U₃O₈. Profit will be determined as revenue less certain operating, exploration, reclamation and capital costs (applied to Saskatchewan uranium production). Under the new system, both exploration and capital costs will be deductible at the discretion of the producer.

MANAGEMENT’S DISCUSSION AND ANALYSIS    43

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.

Also, as previously reported, the net basic royalty (basic royalty of 5% less the Saskatchewan resource credit) increased from 4.0% to 4.25% effective April 1, 2013. Other than the increase of the rate, there were no changes to the determination of the basic royalty, which continues to be levied by the province on the gross revenue from the sales of Saskatchewan uranium production.

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

HIGHLIGHTS	2013		2012		CHANGE
Production volume (million kgU)		14.9		14.2		5	%
Sales volume (million kgU)		17.6		16.4		7	%
Realized price ($Cdn/kgU)		18.12		17.75		2	%
Average unit cost of sales ($Cdn/kgU) (including D&A)		15.16		15.24		(1	)%
Revenue ($ millions)		319		291		10	%
Gross profit ($ millions)		52		41		27	%
Gross profit (%)		16		14		14	%

Total revenue increased by 10% due to a 7% increase in sales volumes and a 2% increase in the realized price.

The total cost of products and services sold (including D&A) increased by 7% ($267 million compared to $250 million in 2012) due to the increase in sales volumes.

The net effect was an $11 million increase in gross profit.

Outlook for 2014

In 2014, we plan to produce 13 million to 14 million kgU, and we expect sales volumes to be 5% to 10% lower than in 2013. Overall revenue is expected to decrease by 5% to 10% as a result of the lower sales volumes. We expect the unit cost of product sold (including D&A) to increase by 0% to 5%; therefore, overall gross profit will decrease as a result.

NUKEM

($ MILLIONS EXCEPT WHERE INDICATED)	2013
	NUKEM			PURCHASE ACCOUNTING			CONSOLIDATED
Uranium sales (million lbs)		8.9			—			8.9
Revenue		503			(38	)		465
Cost of product sold (including D&A)		420			25			445
Gross profit (loss)		83			(63	)		20
Net earnings (loss)		50			(43	)		7
Adjustments on derivatives1		(3	)		—			(3	)
NUKEM inventory write-down		—			10			10
Adjusted net earnings1		47			(33	)		14
Cash provided by operations		6			—			6

¹  Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (non-IFRS measure, see page 28).

On January 9, 2013, we acquired NUKEM for cash consideration of €107 million ($140 million (US)). We also assumed NUKEM’s net debt, which amounted to about €79 million ($104 million (US)).

44     CAMECO CORPORATION

In accordance with the purchase agreement, we paid Advent additional consideration of €6,075,000 ($7,808,000), representing a share of NUKEM’s 2012 earnings. There will be no additional payments to Advent related to the transaction.

For accounting purposes, the purchase price is allocated to the assets and liabilities acquired based on their fair values as of the acquisition date. The purchase price allocation is provided in the table below.

Much of the purchase price was related to nuclear fuel inventories and the portfolio of sales and purchase contracts acquired. The amounts attributed to inventory and contracts were based on market values as at the acquisition date. They will be charged to earnings in the period(s) in which related transactions occur. The amount categorized as goodwill reflects the value assigned to the expected future earnings capabilities of the organization. This is the earnings potential that we anticipate will be realized through new business arrangements. Goodwill is not amortized and is tested for impairment at least annually.

PURCHASE PRICE ALLOCATION

($US MILLIONS)
Net assets
Working capital	(22	)
Inventory	165
Sales, purchase contracts and other intangibles	88
Goodwill	88
Debt	(117	)
Deferred taxes	(54	)
Net assets acquired	148
Financed by
Cash	140
Additional consideration (earn-out provision)	8
Liabilities and equity	148

During 2013, NUKEM delivered 8.9 million pounds of uranium. On a consolidated basis, NUKEM contributed $465 million in revenues and $20 million in gross profit. Adjusted net earnings were $14 million (non-IFRS measure, see page 28). NUKEM’s contribution to our earnings is significantly impacted by our purchase price accounting. Excluding the impact of the purchase accounting, NUKEM’s adjusted net earnings (non-IFRS measure, see page 28) were $47 million for the year. NUKEM’s operating activities provided $6 million in cash during 2013 compared to our expectation of $50 million to $70 million. During the fourth quarter, we concluded a product purchase that had previously been planned for early 2014, reducing our reported cash flows for 2013 by approximately $55 million.

Uranium to be purchased under contractual fixed price arrangements and inventory on hand at the acquisition date were valued using the spot price at that time. The decline in the spot price in recent months has caused the carrying values of certain quantities to exceed their estimated realizable value, and we recorded an initial charge of $17 million ($11 million net of tax) and a subsequent recovery of $3 million ($1 million net of tax).

As noted above, much of the NUKEM purchase price was attributable to inventories and the portfolio of contracts. With respect to nuclear fuel inventories, amounts assigned were based on market values as of the date of acquisition. As these quantities are delivered to NUKEM’s customers, we will adjust the cost of product sold to reflect the values at the acquisition date, regardless of NUKEM’s historic costs.

As of the date of the purchase agreement, had NUKEM’s sales and purchase contracts been settled, it would have realized significant financial benefit. As a result, we paid a premium to acquire the portfolio. Accordingly, a portion of the purchase price has been attributed to the various contracts. In our accounting for NUKEM, we will amortize the amounts assigned to the portfolio in the periods in which NUKEM transacts under the relevant contracts. The net effect is a reduction in reported profit margins relative to NUKEM’s results. We expect the majority of the amount allocated to the contract portfolio will be amortized within two years.

MANAGEMENT’S DISCUSSION AND ANALYSIS    45

Outlook for 2014

For 2014, NUKEM expects to deliver between 9 million and 11 million pounds of uranium, resulting in an increase in total revenues of up to 5% compared to 2013. NUKEM expects to incur administration costs similar to 2013. The effective income tax rate is expected to remain in the range of 30% to 35%.

Electricity

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

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	2013			2012			CHANGE
Output—terawatt hours (TWh)		24.8			26.8			(7	)%
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		87	%		94	%		(7	)%
Realized price ($/MWh)		54	1		55	2		(2	)%
Average Ontario electricity spot price ($/MWh)		25			23			9	%
Revenue		1,370			1,487			(8	)%
Operating costs (net of cost recoveries)		1,001			945			6	%
Cash costs		777			724			7	%
Non-cash costs		224			221			1	%
Income before interest and finance charges		369			542			(32	)%
Interest and finance charges		8			26			(69	)%
Cash from operations		649			523			24	%
Capital expenditures		237			194			22	%
Distributions		330			425			(22	)%
Capital calls		42			63			(33	)%

¹ Based on actual generation of 24.8 TWh plus deemed generation of 0.6 TWh

² Based on actual generation of 26.8 TWh plus deemed generation of 0.4 TWh

OUR EARNINGS FROM BPLP

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	2013			2012			CHANGE
BPLP’s earnings before taxes (100%)		361			516			(30	)%
Cameco’s share of pretax earnings before adjustments (31.6%)		114			163			(30	)%
Proprietary adjustments		(5	)		(6	)		(17	)%
Earnings before taxes from BPLP		109			157			(31	)%

BPLP’s decreased results in 2013 when compared to 2012 are partially the result of revenues being 8% lower than in 2012 due to a 7% decrease in generation and a 2% decrease in realized electricity prices. BPLP’s average realized price reflects spot sales, revenue recognized under BPLP’s agreement with the Ontario Power Authority (OPA) and revenue from financial contracts.

BPLP has an agreement with the OPA under which output from each B reactor is supported by a floor price (currently $52.34/MWh) that is adjusted annually for inflation. The floor price mechanism and any associated payments to BPLP for the output from each individual B reactor will expire on a date specified in the agreement. The expiry dates are 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 to the extent that the floor price for the particular year exceeds the average spot price for that year.

The agreement also provides for payment if the Independent Electricity System Operator (IESO) reduces BPLP’s generation because Ontario’s baseload generation supply is higher than required. The amount of the reduction is considered ‘deemed generation’, for which BPLP is paid either the spot price or the floor price—whichever is higher. The compensation for deemed generation is a reflection of the Bruce B units’ ability to provide flexible output to the Ontario market, and the relatively high fixed cost nature of the business. Deemed generation was 0.6 TWh in 2013 and 0.4 TWh in 2012.

46     CAMECO CORPORATION

During 2013, BPLP recognized revenue of $698 million under the agreement with the OPA, compared to $773 million in 2012.

BPLP also has financial contracts in place that reflect market conditions at the time they were signed. BPLP receives or pays the difference between the contract price and the spot price. During 2013, gains on BPLP’s contracting activity were $59 million, compared to $108 million in 2012.

BPLP’s capacity factor was 87% in 2013, down from 94% in 2012 due to a higher volume of outage days during the year. In 2013, there were 140 planned and 20 unplanned outage days, compared to 46 planned and 25 unplanned outage days in 2012.

In addition, BPLP’s decreased results in 2013 when compared to 2012 were also partially the result of higher operating costs. BPLP’s operating costs were $1.0 billion this year compared to $945 million in 2012 due to higher maintenance costs incurred primarily as a result of more planned outage days than in 2012.

The net effect was a decrease in our share of earnings before taxes of 31%.

BPLP distributed $330 million to the partners in 2013. Our share was $104 million. BPLP capital calls to the partners in 2013 were $42 million. Our share was $13 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

Subject to closing, we have sold our entire interest in BPLP and related entities effective December 31, 2013. See Acquisitions and divestitures on page 36 for details.

MANAGEMENT’S DISCUSSION AND ANALYSIS    47

Fourth quarter results

Fourth quarter consolidated results

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED DECEMBER 31				CHANGE
	2013		2012
Revenue		977		846		15	%
Gross profit		185		255		(27	)%
Net earnings attributable to equity holders		64		41		56	%
$ per common share (basic)		0.16		0.10		60	%
$ per common share (diluted)		0.16		0.10		60	%
Adjusted net earnings (non-IFRS, see page 28)		150		233		(36	)%
$ per common share (adjusted and diluted)		0.38		0.59		(36	)%
Cash provided by operations (after working capital changes)		154		286		(46	)%

NET EARNINGS

In the fourth quarter of 2013, our net earnings were $64 million ($0.16 per share diluted), an increase of $23 million compared to $41 million ($0.10 per share diluted) in 2012, mainly due to:

• the impact of a one-time $168 million write-down of our investment in the Kintyre project in the fourth quarter of 2012

• lower exploration and administrative expenditures

• higher income tax recovery

offset by:

• lower uranium gross profits due to lower sales volumes and higher average unit cost of sales

• a $70 million write-down of our Talvivaara asset, due to their weakened financial position and pending corporate restructuring

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

On an adjusted basis, our earnings this quarter were $150 million ($0.38 per share diluted) compared to $233 million ($0.59 per share diluted) (non-IFRS measure, see below) in the fourth quarter of 2012, mainly due to:

• lower uranium gross profits due to lower sales volumes and higher average unit cost of sales

offset by:

• lower exploration and administrative expenditures

• higher income tax recovery

We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our financial performance from period to period. See page 28 for more information. The table below reconciles adjusted net earnings with our net earnings.

($ MILLIONS)	THREE MONTHS ENDED DECEMBER 31
	2013			2012
Net earnings attributable to equity holders		64			41
Adjustments
Adjustments on derivatives1 (pre-tax)		36			33
NUKEM inventory write-down recovery		(3	)		—
Impairment on Talvivaara asset		70			—
Impairment on non-producing property		—			168
Income taxes on adjustments		(17	)		(9	)
Adjusted net earnings		150			233

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

48     CAMECO CORPORATION

ADMINISTRATION

As a result of restructuring activities, direct administration costs were $45 million in the quarter, $8 million lower than the same period last year. Stock-based compensation expenses were $2 million higher than the fourth quarter of 2012. See note 27 to the financial statements.

($ MILLIONS)	THREE MONTHS ENDED DECEMBER 31				CHANGE
	2013		2012
Direct administration		45		53		(15	)%
Stock-based compensation		6		4		50	%
Total administration		51		57		(11	)%

Quarterly trends

HIGHLIGHTS ($ MILLIONS EXCEPT PER SHARE AMOUNTS)	2013									2012
	Q4		Q3		Q2			Q1		Q41		Q31		Q21			Q11
Revenue		977		597		421			444		846		296		282			467
Net earnings attributable to equity holders		64		211		34			9		41		79		5			128
$ per common share (basic)		0.16		0.53		0.09			0.03		0.10		0.20		0.01			0.33
$ per common share (diluted)		0.16		0.53		0.09			0.03		0.10		0.20		0.01			0.33
Adjusted net earnings (non-IFRS, see page 28)		150		208		61			26		233		49		31			121
$ per common share (adjusted and diluted)		0.38		0.53		0.14			0.07		0.59		0.12		0.08			0.31
Cash provided by operations (after working capital changes)		162		136		(37	)		269		286		36		(117	)		374

¹  Our quarterly results have been revised in accordance with IFRS 11 – Joint Arrangements and IAS 19 – Employee Benefits.

Key things to note:

• Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 65% of consolidated revenues in the fourth quarter of 2013 and 74% of consolidated revenues in the fourth quarter of 2012

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

• Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our results from period to period (see page 28 for more information).

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

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    49

Fourth quarter results by segment

Uranium

HIGHLIGHTS	THREE MONTHS ENDED DECEMBER 31				CHANGE
	2013		2012
Production volume (million lbs)		7.5		6.5		15	%
Sales volume (million lbs)		12.7		14.5		(12	)%
Average spot price ($US/lb)		35.03		42.46		(17	)%
Average long-term price ($US/lb)		50.00		58.50		(15	)%
Average realized price
($US/lb)		47.76		49.97		(4	)%
($Cdn/lb)		49.80		49.37		1	%
Average unit cost of sales ($Cdn/lb) (including D&A)		37.94		32.85		15	%
Revenue ($ millions)		631		716		(12	)%
Gross profit ($ millions)		150		240		(38	)%
Gross profit (%)		24		34		(29	)%

Production volumes this quarter were 15% higher compared to the fourth quarter of 2012, mainly due to higher production at McArthur River/Key Lake, Rabbit Lake, Inkai, and Smith-Ranch Highland with the rampup of the North Butte satellite operation. See Our operations and projects starting on page 54 for more information.

Uranium revenues were down 12% due to a 12% decrease in sales volumes, which represents normal quarterly variance in our delivery schedule.

The average realized price increased slightly compared to 2012 despite a 17% drop in the spot price, due to the mix of contract deliveries, higher US dollar prices under fixed price contracts, and the effect of foreign exchange. In the fourth quarter of 2013, our realized foreign exchange rate was $1.04 compared to $0.99 in the prior year.

Total cost of sales (including D&A) increased by 1% ($481 million compared to $476 million in 2012). This was mainly the result of a 15% increase in the average unit cost of sales, offset by a 12% decrease in sales volumes.

The unit cost of sales increased due to an increase in the non-cash costs of produced material in the fourth quarter compared to the same period in 2012, and an increase in the unit cost of material purchased.

In 2013, we purchased about 10 million pounds of material under the Russian HEU commercial agreement, more than the annual 7 million historically purchased. Some of this additional material was made available under an option in the agreement, which we exercised in 2006. Under the agreement, pricing of this option material was at a discount to spot prices at the time of delivery. We received the option material in the fourth quarter as our final purchase under the Russian HEU commercial agreement.

In addition, in the fourth quarter, we had back-to-back purchase and sale arrangements that, while profitable, required we purchase material at a price higher than the current spot price.

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

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

50     CAMECO CORPORATION

($/LB)	THREE MONTHS ENDED DECEMBER 31				CHANGE
	2013		2012
Produced
Cash cost		15.61		17.01		(8)	%
Non-cash cost		9.42		8.41		12	%
Total production cost		25.03		25.42		(2)	%
Quantity produced (million lbs)		7.5		6.5		15	%
Purchased
Cash cost		37.26		32.94		13	%
Quantity purchased (million lbs)		4.4		2.8		57	%
Totals
Produced and purchased costs		29.55		27.69		7	%
Quantities produced and purchased (million lbs)		11.9		9.3		28	%

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

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

To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the fourth quarters of 2013 and 2012.

CASH AND TOTAL COST PER POUND RECONCILIATION

($ MILLIONS)	THREE MONTHS ENDED DECEMBER 31				CHANGE
	2013		2012
Cost of product sold		359.8		394.4		(9)	%
Add / (subtract)
Royalties		(52.5)		(51.7)		2	%
Standby charges		(11.1)		(7.7)		44	%
Other selling costs		(4.8)		(3.3)		45	%
Change in inventories		(10.3)		(128.9)		(92)	%
Cash operating costs (a)		281.1		202.8		39	%
Add / (subtract)
Depreciation and amortization		121.2		82.1		48	%
Change in inventories		(50.7)		(27.4)		85	%
Total operating costs (b)		351.6		257.5		37	%
Uranium produced & purchased (millions lbs) (c)		11.9		9.3		28	%
Cash costs ($/lb) (a ÷ c)		23.62		21.81		8	%
Total costs ($/lb) (b ÷ c)		29.55		27.69		7	%

MANAGEMENT’S DISCUSSION AND ANALYSIS    51

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

HIGHLIGHTS	THREE MONTHS ENDED DECEMBER 31				CHANGE
	2013		2012
Production volume (million kgU)		2.7		3.3		(18)	%
Sales volume (million kgU)		6.5		6.0		8	%
Average realized price ($Cdn/kgU)		17.24		17.16		—
Average unit cost of sales ($Cdn/kgU) (including D&A)		14.42		14.06		3	%
Revenue ($ millions)		112		103		9	%
Gross profit ($ millions)		18		19		(5)	%
Gross profit (%)		16		18		(11)	%

Total revenue increased by 9% due to an 8% increase in sales volumes.

The total cost of sales (including D&A) increased by 9% ($93 million compared to $85 million in the fourth quarter of 2012) mainly due to an 8% increase in sales volumes.

The net effect was a $1 million decrease in gross profit.

NUKEM

($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED DECEMBER 31, 2013						CONSOLIDATED
	NUKEM			PURCHASE ACCOUNTING
Uranium sales (million lbs)		3.3			—			3.3
Revenue		220			(32	)		188
Cost of product sold (including D&A)		202			(33	)		169
Gross profit		18			1			19
Net earnings		12			1			13
Adjustments on derivatives1		(1	)		—			(1	)
NUKEM inventory write-down		—			(1	)		(1	)
Adjusted net earnings1		11			—			11
Cash provided by operations		9			—			9

¹  Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (non-IFRS measure, see page 28).

During the fourth quarter of 2013, NUKEM delivered 3.3 million pounds of uranium. On a consolidated basis, NUKEM contributed $188 million in revenues and gross profit of $19 million. Adjusted net earnings were $11 million (non-IFRS measure, see page 28). During the quarter, NUKEM’s operating activities provided $9 million in cash, which was lower than expected due to the timing of a product purchase that was originally planned for early 2014 occurring in December of 2013.

52     CAMECO CORPORATION

Electricity

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

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED DECEMBER 31						CHANGE
	2013			2012
Output—terawatt hours (TWh)		6.9			7.2			(4	)%
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		96	%		100	%		(4	)%
Realized price ($/MWh)		54	1		54			—
Average Ontario electricity spot price ($/MWh)		22			24			(8	)%
Revenue		383			393			(3	)%
Operating costs (net of cost recoveries)		234			236			(1	)%
Cash costs		173			179			(3	)%
Non-cash costs		61			57			7	%
Income before interest and finance charges		149			157			(5	)%
Interest and finance charges		(4	)		6			(167	)%
Cash from operations		181			100			81	%
Capital expenditures		56			54			4	%
Distributions		125			140			(11	)%
Capital calls		15			14			7	%

¹  Based on actual generation of 6.9 TWh plus deemed generation of 0.2 TWh in the fourth quarter of 2013.

OUR EARNINGS FROM BPLP

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)	THREE MONTHS ENDED DECEMBER 31						CHANGE
	2013			2012
BPLP’s earnings before taxes (100%)		153			151			1	%
Cameco’s share of pretax earnings before adjustments (31.6%)		48			48			—
Proprietary adjustments		(1	)		(2	)		(50	)%
Earnings before taxes from BPLP		47			46			2	%

Total electricity revenue decreased 3% this quarter due to a lower output. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA, and financial contract revenue. BPLP recognized revenue of $212 million this quarter under its agreement with the OPA, compared to $198 million in the fourth quarter of 2012. Gains on BPLP’s contract activity in the fourth quarter of 2013 were $17 million, compared to $22 million in the fourth quarter of 2012.

The capacity factor was 96% this quarter, down from 100% in the fourth quarter of 2012. There were seven unplanned outage days in the quarter, compared to no outage days in the fourth quarter of 2012.

Operating costs this quarter of $234 million were similar to the $236 million in 2012.

The result was $47 million in earnings before taxes (our share) in the fourth quarter of 2013 compared to $46 million in earnings before taxes in the fourth quarter of 2012.

BPLP distributed $125 million to the partners in the fourth quarter. Our share was $40 million. BPLP capital calls to the partners in the fourth quarter were $15 million. Our share was $5 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

MANAGEMENT’S DISCUSSION AND ANALYSIS    53

Our operations and projects

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

57	URANIUM – PRODUCTION OVERVIEW
57	OUTLOOK
58	URANIUM OPERATING PROPERTIES
58	MCARTHUR RIVER / KEY LAKE
64	RABBIT LAKE
66	SMITH RANCH-HIGHLAND
67	CROW BUTTE
68	INKAI
71	URANIUM – DEVELOPMENT PROJECT
71	CIGAR LAKE
76	URANIUM – PROJECTS UNDER EVALUATION
76	MILLENNIUM
76	YEELIRRIE
77	KINTYRE
78	URANIUM – EXPLORATION AND CORPORATE DEVELOPMENT
80	FUEL SERVICES – REFINING, CONVERSION AND FUEL MANUFACTURING
80	BLIND RIVER REFINERY
81	PORT HOPE CONVERSION SERVICES
81	CAMECO FUEL MANUFACTURING INC. (CFM)
81	SPRINGFIELDS FUELS LTD. (SFL)
83	NUKEM GMB

54     CAMECO CORPORATION

Managing the risks

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

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

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

Regulatory risks

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

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

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

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

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

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

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

Environmental risks

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

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

At the end of 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS    55

We provide financial assurances for decommissioning and reclamation such 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.

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

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

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

In 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.

Operational risks

Other operational risks and hazards include:

•     environmental damage   •     industrial and transportation accidents   •     labour shortages, disputes or strikes   •     cost increases for labour, contracted or purchased materials, supplies and services   •     shortages of required materials, supplies and equipment   •     transportation disruptions   •     electrical power interruptions   •     equipment failures   •     non-compliance with laws and licences   •     catastrophic accidents •     fires   •     blockades or other acts of social or political activism   •     natural phenomena, such as inclement weather conditions, floods and earthquakes   •     unusual, unexpected or adverse mining or geological conditions   •     underground floods   •     ground movement or cave-ins   •     tailings pipeline or dam failures   •     technological failure of mining methods

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

56     CAMECO CORPORATION

Uranium – production overview

Production in our uranium segment this quarter was 1 million pounds higher compared to the fourth quarter of 2012. Production for the year was 1.7 million pounds higher than in 2012. We set new annual and quarterly production records with these results. See Uranium – operating properties starting on page 58 for more information.

URANIUM PRODUCTION

CAMECO’S SHARE	THREE MONTHS ENDED DECEMBER 31				YEAR ENDED DECEMBER 31
(MILLION LBS)	2013		2012		2013		2012		2013 PLAN			2014 PLAN
McArthur River/Key Lake		4.0		3.5		14.1		13.6		13.6	1		13.1
Rabbit Lake		2.1		1.7		4.1		3.8		4.2			4.1
Smith Ranch-Highland		0.5		0.3		1.7		1.1		1.6	1		2.0
Crow Butte		0.2		0.2		0.7		0.8		0.7	1		0.6
Inkai		0.7		0.8		3.0		2.6		2.9			3.0
Cigar Lake		—		—		—		—		—	1		1.0 – 1.5
Total		7.5		6.5		23.6		21.9		23.2			23.8 – 24.3

¹  We updated our initial 2013 plan for McArthur River/Key Lake (to 13.6 million pounds from 13.2 million pounds), US ISR (to 2.3 million pounds from 2.6 million pounds) and Cigar Lake (to nil from 0.3 million pounds) in our Q3 MD&A.

Outlook

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. As a result of the longer-than-anticipated uncertainty that continues to persist in today’s market, it is no longer appropriate to pursue significant production growth to a fixed target. Although we still have an extensive portfolio of assets from which we can increase our production capacity, we have eliminated our 2018 supply target of 36 million pounds in order to allow us to respond to market signals, and as a result, it is no longer appropriate to provide a long-term production forecast.

We plan to:

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

• ensure continued reliable, low-cost production at Inkai

• successfully bring on and ramp up production at Cigar Lake

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    57

Uranium operating properties

	McArthur River / Key Lake
	McArthur River is the world’s largest, high-grade uranium mine, and Key Lake is the largest uranium mill in the world.
	Ore grades at the McArthur River mine are 100 times the world average, which means it can produce more than 18 million pounds per year by mining only 150 to 200 tonnes of ore per day. We are the operator.
	McArthur River is one of our three material uranium properties.

Location	Saskatchewan, Canada
Ownership	69.805% – McArthur River 83.33% – Key Lake
End product	Uranium concentrates
ISO certification	ISO 14001 certified
Mine type	Underground
Estimated reserves (our share)	251.6 million pounds (proven and probable), average grade U3O8: 15.76%
Estimated resources (our share)	9.5 million pounds (measured and indicated), average grade U3O8: 4.81% 39.9 million pounds (inferred), average grade U3O8: 7.38%
Mining methods	Primary: raiseboring; Secondary: blasthole stoping, boxhole boring
Licenced capacity	Mine and mill: 18.7 million pounds per year (can be exceeded – see Flexibility provisions)
Total production: 2000 to 2013 (100% basis)         1983 to 2002	250.6 million pounds (McArthur River/Key Lake) 209.8 million pounds (Key Lake)
2013 production (our share)	14.1 million pounds (20.1 million pounds on 100% basis)
2014 forecast production (our share)	13.1 million pounds (18.7 million pounds on 100% basis)
Estimated decommissioning cost (100% basis)	$48 million – McArthur River $218 million – Key Lake (estimate currently under review)

BACKGROUND

Mining methods and techniques

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

Ground freezing

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

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We have used the raisebore mining method to successfully 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.

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

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

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

In 2013, the CNSC granted approval for the use of two secondary extraction methods: blasthole stoping and boxhole boring. 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 a few mines around the world, but had not been used for uranium mining prior to testing at McArthur River.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    59

Blasthole stoping

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

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

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.

2013 UPDATE

Production

Total production from McArthur River/Key Lake was 20.1 million pounds, which is the highest annual output from a uranium facility anywhere in the world. Our share of production in 2013 was 14.1 million pounds U₃O₈, 4% higher than our forecast for the year, and 4% higher than annual production in 2012.

At McArthur River and Key Lake we realized benefits under the production flexibility provision in our operating licences (see Flexibility provisions below). Ongoing efforts to improve the efficiency and reliability of the Key Lake mill resulted in record mill performance.

Licensing and production capacity

On October 29, 2013, the CNSC granted a renewal of our McArthur River and Key Lake operating licences. The licence term is from November 1, 2013 to October 31, 2023.

Flexibility provisions

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.

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.

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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 increases, we must continue to successfully transition into new mine areas through mine development and investment in support infrastructure. In addition, we plan to:

• 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

New mining areas

We completed installation of the freezewall and brine lines in the upper mining area of zone 4 north. We began freezing the ground in the third quarter of 2013, with plans to start mining the zone in late 2014.

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

Key Lake extension project and mill revitalization

The Key Lake mill began operating in 1983 and is currently licensed to produce 18.7 million pounds (100% basis) per year. Mill production at Key Lake is expected to closely follow McArthur River production, subject to receipt of regulatory approval. As part of our Key Lake extension environmental assessment (EA), we are seeking approval to increase Key Lake’s nominal annual production rate to 25 million pounds and to increase our tailings capacity; in 2014, we expect the federal and provincial EA to conclude and expect a decision to be made on these increases.

The mill revitalization plan includes upgrading circuits with new technology to simplify operations and improve environmental performance. Major components of a new calciner circuit were installed in 2013 and commissioning is expected to be completed in 2014. As part of the revitalization plan, we also replaced the existing electrical substation in order to meet future electrical demands.

Tailings capacity

This year we:

• submitted the final environmental impact statement for review by the regulators, and plan to pursue the required regulatory approvals in 2014

• completed flattening of the Deilmann tailings management facility pitwalls

Exploration

In 2013, our surface exploration programs continued to test zones of mineralization north of the current mining areas.

PLANNING FOR THE FUTURE

Production

We plan to produce 18.7 million pounds per year (13.1 million pounds our share) until we receive the required regulatory approvals and complete the work necessary to increase production at both McArthur River and Key Lake.

New mining zones

Zone 4 north is the next area to be mined. Freezing has begun and we forecast initial production to start 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS    61

Mill revitalization

In 2014, we expect to:

• complete installation and commissioning of the new calciner

• upgrade the electrical services necessary to add standby electrical generating capacity for the new electrically heated calciner

Key Lake extension project

In 2014, we expect to complete the regulatory process required to increase production to 25 million pounds per year at Key Lake. We will also seek approval to deposit tailings in the Deilmann tailings management facility to a higher level, providing 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.

See Key Lake tailings capacity risk below for additional information.

Exploration

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.

MANAGING OUR RISKS

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

Labour relations

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

Transition to new mining areas

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

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

Key Lake tailings capacity risk

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

In the past, sloughing of material from the pitwalls has resulted in loss of capacity. Technical studies show that stabilizing and reducing water levels in the pit enhances the stability of the pitwalls and reduces the risk of sloughing. In 2009, regulators approved our plan for the long-term stabilization of the Deilmann tailings management facility pitwalls. We implemented the plan and completed the project in 2013. We are proceeding with the environmental assessment to support an application for regulatory approval to deposit tailings to a higher level. This would provide enough tailings capacity to mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

Water inflow risk

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

62     CAMECO CORPORATION

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

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

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

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

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

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

We also manage the risks listed on pages 55 to 56.

MANAGEMENT’S DISCUSSION AND ANALYSIS    63

Uranium – operating properties

Rabbit Lake   The Rabbit Lake operation, which opened in 1975, is the longest operating uranium production facility in North America, and the second largest uranium mill in the world.

Location	Saskatchewan, Canada
Ownership	100%
End product	Uranium concentrates
ISO certification	ISO 14001 certified
Mine type	Underground
Estimated reserves	20.3 million pounds (proven and probable), average grade U3O8: 0.56%
Estimated resources	20.2 million pounds (indicated), average grade U3O8: 0.80% 9.0 million pounds (inferred), average grade U3O8: 0.58%
Mining methods	Vertical blasthole stoping
Licenced capacity	Mill: maximum 16.9 million pounds per year; currently 11 million
Total production: 1975 to 2013	190.1 million pounds
2013 production	4.1 million pounds
2014 forecast production	4.1 million pounds
Estimated decommissioning cost	$203 million

2013 UPDATE

Production

Production this year was 8% higher than 2012 production as a result of improved efficiency of the mill operating schedule.

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

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 Powell Zone). See Mineral reserves and resources on page 84 for more information.

Licensing

On October 29, 2013, the CNSC granted a renewal of our Rabbit Lake operating licences. The licence term is from November 1, 2013 to October 31, 2023.

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PLANNING FOR THE FUTURE

Production

We expect to produce 4.1 million pounds in 2014.

Tailings capacity

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

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

Exploration

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

Reclamation

As part of 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 over $0.5 million in 2014.

MANAGING OUR RISKS

We manage the risks listed on pages 55 to 56.

MANAGEMENT’S DISCUSSION AND ANALYSIS    65

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 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 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 (measured and indicated), average grade U3O8: 0.07% 0.8 million pounds (inferred), average grade U3O8: 0.06%
Mining methods	In situ recovery (ISR)
Licenced 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)

2013 UPDATE

Production

Production this year was 6% higher than our forecast and significantly higher than 2012 production, with new mine units contributing to production at Smith Ranch-Highland in 2013, as well as the startup of the North Butte satellite.

Our North Butte satellite began production during the second quarter and produced 300,000 pounds in 2013. We expect to ramp up to a target annual production rate of more than 700,000 pounds per year by 2015 from the North Butte satellite operation. We continue to seek regulatory approvals to proceed with the rest of our expansion plans.

Licensing

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

PLANNING FOR THE FUTURE

Production

In 2014, we expect to produce 2.0 million pounds.

MANAGING OUR RISKS

We manage the risks listed on pages 55 to 56.

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Uranium – operating properties

Crow Butte   Crow Butte was discovered in 1980 and began production in 1991. It is the first uranium mine in Nebraska, and is a significant contributor to the economy of northwest Nebraska.

Location	Nebraska, US
Ownership	100%
End product	Uranium concentrates
ISO certification	ISO 14001 certified
Estimated reserves	2.3 million pounds (proven), average grade U3O8: 0.11%
Estimated resources	14.6 million pounds (indicated), average grade U3O8: 0.27% 2.9 million pounds (inferred), average grade U3O8: 0.12%
Mining methods	In situ recovery (ISR)
Licenced capacity (processing plants and wellfields)	2.0 million pounds per year
Total production: 2002 to 2013	9.1 million pounds
2013 production	0.7 million pounds
2014 forecast production	0.6 million pounds
Estimated decommissioning cost	$44 million (US)

2013 UPDATE

Production

Production this year was as forecast, but slighter lower than 2012 production.

Licensing

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

PLANNING FOR THE FUTURE

Production

In 2014, we expect to produce 0.6 million pounds.

Managing our risks

We manage the risks listed on pages 55 to 56.

MANAGEMENT’S DISCUSSION AND ANALYSIS    67

Uranium – operating properties

Inkai   Inkai is a very significant uranium deposit, located in Kazakhstan. There are two production areas (blocks 1 and 2) and an exploration area (block 3). The operator is joint venture Inkai limited liability partnership, which we jointly own (60%) with Kazatomprom (40%).   Inkai is one of our three material uranium properties.

Location	South Kazakhstan
Ownership	60%
End product	Uranium concentrates
Certifications	BSI OHSAS 18001 ISO 14001 certified
Estimated reserves (our share)	50.4 million pounds (proven and probable), average grade U3O8: 0.07%
Estimated resources (our share)	28.3 million pounds (indicated), average grade U3O8: 0.08% 146.3 million pounds (inferred), average grade U3O8: 0.05%
Mining methods	In situ recovery (ISR)
Licenced capacity (wellfields)	5.2 million pounds per year, (our share 3.0 million pounds per year)
Total production: 2008 to 2013 (our share)	12.0 million pounds
2013 production (our share)	3.0 million pounds (5.2 million pound on 100% basis)
2014 forecast production (our share)	3.0 million pounds (5.2 million pounds on 100% basis)
Estimated decommissioning cost (100% basis )	$14 million (US)

2013 UPDATE

Production

Production this year was slightly higher than our forecast for the year and 15% higher than production in 2012. Inkai added new wellfields to the production mix, which increased the head grade and resulted in higher 2013 production.

Licensing

In December 2013, Inkai received government approval of an amendment to the resource use contract to increase production from blocks 1 and 2 to 5.2 million pounds (100% basis). Our share of Inkai’s annual production is 3.0 million pounds with the processing plant at full capacity.

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

We 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).

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Uranium conversion project and doubling production update

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

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

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

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

Block 3 exploration

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

PLANNING FOR THE FUTURE

Production

We expect our share of production to be 3.0 million pounds in 2014 from blocks 1 and 2. We expect to maintain production at this level until the potential expansion under the 2012 MOA proceeds.

Block 3 exploration

In 2014, Inkai expects to:

• complete construction of the test leach facility and test wellfields

• start operation of the test wellfields and begin 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

MANAGING OUR RISKS

Supply of sulphuric acid

There were no interruptions to sulphuric acid supply during 2013. Given the importance of sulphuric acid to Inkai’s mining operations and shortages in previous years, we continue to closely monitor its availability. Our production may be less than forecast if there is a shortage.

Political risk

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    69

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

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

With the 2010 subsoil law, the government continues to weaken its stabilization guarantee. The government is broadly applying the national security exception to encompass security over strategic national resources.

The resource use contract contains significantly broader stabilization provisions than the 2010 subsoil law, and these contract provisions currently apply to us.

To date, the 2010 subsoil law has not had a significant impact on Inkai. We continue to assess the impact. See our annual information form for an overview of this change in law.

We also manage the risks listed on pages 55 to 56.

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Uranium – development project

Cigar Lake   Cigar Lake is the world’s second largest high-grade uranium deposit, with grades that are 100 times the world average. We are a 50% owner and the mine operator.   Cigar Lake, which is being developed and scheduled to begin production this year, is one of our three material uranium properties.

Location	Saskatchewan, Canada
Ownership	50.025%
End product	Uranium concentrates
Mine type	Underground
Estimated reserves (our share)	108.4 million pounds (proven and probable), average grade U3O8: 18.30%
Estimated resources (our share)	1.1 million pounds (measured and indicated), average grade U3O8: 2.27% 49.5 million pounds (inferred), average grade U3O8: 12.01%
Mining methods	Jet boring
Target production date	First mine production in the first quarter of 2014 Begin processing ore at the McClean Lake mill by the end of the second quarter of 2014
Target annual production (our share)	9 million pounds at full production (18.0 million pounds on 100% basis)
2014 forecast production (our share)	1.0 – 1.5 million pounds (2.0 to 3.0 million pounds on 100% basis)
Estimated decommissioning cost (100% basis )	$49 million

MANAGEMENT’S DISCUSSION AND ANALYSIS    71

BACKGROUND

Development

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

Mining method

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

Bulk freezing

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

Our plan is to use a hybrid freezing approach. We will use surface freezing to support the rampup period and underground freezing for the longer term development of the mine. Through 2013, we continued to drill freezeholes from surface, expand the surface freezing infrastructure and put the new freezeholes in operation. To manage our risks and meet our production schedule, the area being mined must meet specific ground freezing requirements before we begin jet boring.

Jet boring

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

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

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

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

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

• starting the process again with the next cavity

Jet boring system process

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

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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, and expect to begin ore production from the mine during the first quarter of 2014.

Milling

All of Cigar Lake’s ore slurry will be processed at the McClean Lake mill, operated by AREVA. The McClean Lake mill requires modification and expansion to process and package all of Cigar Lake’s current mineral reserves. The Cigar Lake joint venture has agreed to pay for the capital costs for such modification and expansion.

In September 2013, AREVA advised us that it had determined that further mill modifications were required before they could begin processing Cigar Lake ore. The McClean Lake mill is expected to begin processing Cigar Lake ore by the end of the second quarter of 2014.

2013 UPDATE

During the year, we:

• completed construction and began commissioning of all infrastructure required to begin ore production

• successfully tested the jet boring system in waste and began commissioning in ore

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

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 in remediation expenses

• expensed about $100 million in 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 estimated to be 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 mill. Additional expenditures of about $35 million will be required at McClean Lake 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.

Licensing

The CNSC granted a uranium mining licence authorizing construction and operation of the Cigar Lake project. The licence term is from July 1, 2013 to June 30, 2021.

PLANNING FOR THE FUTURE

Production

In 2014, we expect:

• to bring the mine into production in the first quarter of 2014

• processing of the ore to begin at AREVA’s McClean Lake mill by the end of the second quarter of 2014

Rampup schedule

We expect Cigar Lake to produce between 2 million and 3 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.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    73

Caution regarding forward-looking information

Our expectations and plans regarding Cigar Lake, including our expected share of 2014 production, achievement of the full production rate of 18 million pounds by 2018, and capital costs, are forward-looking information. They are based on the assumptions and subject to the material risks discussed on pages 2 and 3, and specifically on these assumptions and risks:

Assumptions

• our Cigar Lake development, mining and production plans succeed

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

• there are no labour disputes or shortages

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

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

• our expectation that 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 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 facility capacity is available

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

Material risks

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

• ground movements or cave-ins

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

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

• sufficient tailings facility capacity is not available

• our mineral reserves estimate is not reliable

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

MANAGING OUR RISKS

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

Mill modifications

There is a risk to Cigar Lake’s ramp up schedule if the McClean Lake 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. We are working closely with AREVA to understand and help mitigate the risks to ensure that mine and mill production schedules are aligned.

Ground freezing

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

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Jet boring mining method and units

Although we have successfully tested the jet boring mining method in waste rock and began commissioning the system in ore, this method has not been proven at full production. As we ramp up production, there may be some technical challenges that 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 to assure successful startup and on-going operations. We are confident we will be able to solve challenges that may arise, but failure to do so would have a significant impact on our business.

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

Water inflow risk

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

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

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

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

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

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

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

We also manage the risks listed on pages 55 to 56.

MANAGEMENT’S DISCUSSION AND ANALYSIS    75

Uranium – projects under evaluation

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

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

Millennium

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

BACKGROUND

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

2013 UPDATE

This year we:

• submitted the final environmental impact statement to regulators

• completed a drill program that successfully increased the indicated resources of the deposit

In 2014, we expect a decision from the CNSC on a construction and operating licence for Millennium. A positive outcome and receipt of a licence would allow us to quickly advance to a development decision on the project, once the market signals that new production is needed.

Yeelirrie

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

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BACKGROUND

In 2012, we paid $430 million (US) (as well as $22 million (US) in stamp duty) to acquire the Yeelirrie uranium deposit. The deposit was discovered in 1972 and is a near-surface calcrete-style deposit that is amenable to open pit mining techniques. It is one of Australia’s largest undeveloped uranium deposits.

2013 UPDATE

This year, we are reporting a new mineral resources estimate in accordance with National Instrument 43-101 – Standards of Disclosure for Mineral Projects (NI 43-101) based on a full document review, data validation, geological re-interpretation and modeling. We have provided the updated estimate in Mineral reserves and resources, starting on page 84.

Kintyre

LOCATION	Western Australia
Ownership	70%
End product	Uranium concentrates
Mine type	Open pit
Estimated resources (our share)	38.7 million pounds (indicated), average grade U3O8: 0.58% 6.7 million pounds (inferred), average grade U3O8: 0.46%

BACKGROUND

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

2013 UPDATE

This year we:

• completed the value engineering study

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

• submitted an Environmental Review and Management Program

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

MANAGING THE RISKS

For all of our projects under evaluation, we manage the risks listed on pages 55 to 56.

Additional risks for Millennium include:

• The English River First Nation (ERFN) selected surface lands covering the Millennium deposit in a claim for Treaty Land Entitlement (TLE). The TLE process does not affect our mineral rights, but it could have an impact on the surface rights and benefits we ultimately negotiate as part of the development of this deposit. Under the collaboration agreement that we signed with ERFN in 2013, the TLE claim will be dropped.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    77

Uranium – exploration and corporate development

Our exploration program is directed at replacing mineral reserves as they are depleted by our production, and ensuring our future growth. We have maintained an active program even during periods of weak uranium prices, which has helped us secure land with exploration and development prospects that are among the best in the world, mainly in Canada, Australia, Kazakhstan and the US. Globally, our land holdings total 2.0 million hectares (4.9 million acres). In northern Saskatchewan alone, we have direct interests in 584,000 hectares (1.4 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin. Many of our prospects are located close to our existing operations where we have established infrastructure and capacity to expand.

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

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

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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.

PLANNING FOR THE FUTURE

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 exploration 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 Canada and Australia, 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.

ACQUISITION PROGRAM

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    79

Fuel services – refining, conversion and fuel manufacturing

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

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

Blind River Refinery   Blind River is the world’s largest commercial uranium refinery, refining uranium concentrates from mines around the world into UO₃.

Location	Ontario, Canada
Ownership	100%
End product	UO3
ISO certification	ISO 14001 certified
Licensed capacity	24 million kgU as UO3 per year (subject to the completion of certain equipment upgrades)
Estimated decommissioning cost	$39 million

2013 UPDATE

Production

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

MANAGING OUR RISKS

We manage the risks listed on pages 55 to 56.

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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

2013 UPDATE

Production

Fuel services produced 14.9 million kgU, slightly higher than our plan at the beginning of the year and 5% higher than 2012 when we reduced production in response to weak market conditions.

Labour relations

In July, unionized employees at our Port Hope conversion facility accepted new three-year collective agreements, which include a 6% wage increase over the term of the agreements.

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

In December 2012, we received a positive decision on the environmental assessment for the project from Canada’s Environment Minister. In 2013, we began the licensing process with the CNSC, which is required to advance the project. The process will continue in 2014.

MANAGEMENT’S DISCUSSION AND ANALYSIS    81

Springfields toll milling 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.

PLANNING FOR THE FUTURE

Production

We have decreased our production target for 2014 to between 13 million and 14 million kgU in response to weak market conditions.

MANAGING OUR RISKS

We also manage the risks listed on pages 55 to 56.

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NUKEM GmbH

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

BACKGROUND

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

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

NUKEM’s main customers are commercial nuclear power plants using enriched uranium fuel, typically large utilities that are either government-owned, or large-scale utilities with multi-billion dollar market capitalizations and strong credit ratings. NUKEM also trades with converters, enrichers, other traders and investors. It has uranium and uranium-related products under contract until 2022.

NUKEM’s business model

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

MANAGING OUR RISKS

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    83

Mineral reserves and resources

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

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

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

About mineral resources

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

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

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

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

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

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

About mineral reserves

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

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

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

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

The price assumption is based on independent industry and analyst estimates of spot prices and the corresponding long-term prices and reflects our committed and uncommitted sales volumes. For committed sales volumes, the spot and term price assumptions were applied in accordance with the terms of the agreements. For uncommitted sales volumes the same price assumptions were applied using a spot-to-term price ratio of 60:40.

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%).

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Changes this year

Our share of proven and probable mineral reserves went from 465 million pounds U₃O₈ at the end of 2012 to 443 million pounds at the end of 2013. The change in reserves was mainly 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 re-interpretation, re-estimation, and non demonstrated profitability

Measured and indicated mineral resources increased from 244 million pounds U₃O₈ at the end of 2012 to 391 million pounds at the end of 2013. Our share of inferred mineral resources is 289 million pounds U₃O₈.

The variance in resources was mainly the result of:

• the addition of Yeelirrie mineral resources

• the addition of indicated resources at Rabbit Lake from delineation drilling and conversion of inferred to indicated

• the addition of indicated and inferred resources to Millennium from drilling

• the conversion of mineral reserves to resources at Gas Hills

Qualified persons

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

McArthur River/Key Lake

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

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

• Greg Murdock, mine manager, Rabbit Lake, Cameco

• Les Yesnik, general manager, Key Lake, Cameco

Cigar Lake

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

• Eric Paulsen, chief metallurgist, technology group, Cameco

• Scott Bishop, principal mine engineer, 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

MANAGEMENT’S DISCUSSION AND ANALYSIS    85

Important information about mineral reserve and resource estimates

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

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

• geological interpretation

• extraction plans

• commodity prices and currency exchange rates

• recovery rates

• operating and capital costs

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

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

Important information for US investors

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

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

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

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

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

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Mineral reserves

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

Proven and probable

(tonnes in thousands; pounds in millions)

PROPERTY	MINING METHOD		PROVEN						PROBABLE						TOTAL MINERAL RESERVES
			TONNES		GRADE % U3O8		CONTENT (LBS U3O8)		TONNES		GRADE % U3O8		CONTENT (LBS U3O8)		TONNES		GRADE % U3O8		CONTENT (LBS U3O8)		CAMECO’S SHARE OF CONTENT (LBS U3O8)		METALLUR-GICAL RECOVERY (%)
McArthur River		UG		465.2		21.42		219.7		572.2		11.17		140.8		1,037.4		15.76		360.5		251.6		98.7
Cigar Lake		UG		233.6		22.31		114.9		303.5		15.22		101.8		537.1		18.30		216.7		108.4		98.5
Rabbit Lake		UG		43.0		0.29		0.3		1,599.1		0.57		20.0		1,642.1		0.56		20.3		20.3		97
Key Lake		OP		67.5		0.50		0.7								67.5		0.50		0.7		0.6		98.7
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
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
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
Crow Butte		ISR		928.6		0.11		2.3								928.6		0.11		2.3		2.3		85
Total				5,710.8		—		345.7		63,077.6		—		351.5		68,788.5		—		697.2		442.7

Notes

UG – underground

OP – open pit

ISR – in situ recovery

Estimates in the above table:

• use an average uranium price of $63.75 (US)/lb U₃O₈

• are based on an average exchange rate of $1.00 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.

MANAGEMENT’S DISCUSSION AND ANALYSIS    87

Mineral resources

As at December 31, 2013 (100% – only the last column shows our share)

Measured and indicated

(tonnes in thousands; pounds in millions)

PROPERTY	MINING METHOD		MEASURED						INDICATED						TOTAL MEASURED AND INDICATED
			TONNES		GRADE % U3O8		CONTENT (LBS U3O8)		TONNES		GRADE % U3O8		CONTENT (LBS U3O8)		TONNES		GRADE % U3O8		CONTENT (LBS U3O8)		CAMECO’S SHARE (LBS U3O8)
McArthur River		UG		111.2		4.13		10.1		16.7		9.36		3.5		127.9		4.81		13.6		9.5
Cigar Lake		UG		18.9		1.68		0.7		25.5		2.71		1.5		44.4		2.27		2.2		1.1
Rabbit Lake		UG								1,152.6		0.80		20.2		1,152.6		0.80		20.2		20.2
Millennium		UG								1,442.6		2.39		75.9		1,442.6		2.39		75.9		53.0
Phoenix		UG								152.4		15.60		52.3		152.4		15.60		52.3		15.7
Tamarack		UG								183.8		4.42		17.9		183.8		4.42		17.9		10.3
Dawn Lake		OP, UG								347.0		1.69		12.9		347.0		1.69		12.9		7.4
Kintyre		OP								4,315.4		0.58		55.2		4,315.4		0.58		55.2		38.7
Yeelirrie		OP		24,013.5		0.17		92.4		12,626.5		0.13		34.9		36,640.0		0.16		127.3		127.3
Inkai		ISR								29,346.4		0.08		49.2		29,346.4		0.08		49.2		28.3
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
North Butte-Brown Ranch		ISR								7,245.7		0.07		10.8		7,245.7		0.07		10.8		10.8
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
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
Ruby Ranch		ISR								2,215.3		0.08		4.1		2,215.3		0.08		4.1		4.1
Ruth		ISR								1,080.5		0.09		2.1		1,080.5		0.09		2.1		2.1
Shirley Basin		ISR		89.2		0.16		0.3		1,638.2		0.11		4.1		1,727.4		0.12		4.4		4.4
Total				31,707.8		—		123.2		82,976.4		—		383.3		114,684.2		—		506.5		391.2

88     CAMECO CORPORATION

Inferred

(tonnes in thousands; pounds in millions)

PROPERTY	MINING METHOD		TONNES		GRADE % U3O8		CONTENT (LBS U3O8)		CAMECO’S SHARE (LBS U3O8)
McArthur River		UG		350.7		7.38		57.1		39.9
Cigar Lake		UG		373.4		12.01		98.9		49.5
Rabbit Lake		UG		708.5		0.58		9.0		9.0
Millennium		UG		412.4		3.19		29.0		20.2
Phoenix		UG		11.6		29.80		7.6		2.3
Tamarack		UG		45.6		1.02		1.0		0.6
Kintyre		OP		950.2		0.46		9.6		6.7
Inkai		ISR		254,217.9		0.05		254.4		146.3
Smith Ranch-Highland		ISR		6,989.4		0.05		7.9		7.9
North Butte-Brown Ranch		ISR		594.3		0.06		0.8		0.8
Gas Hills-Peach		ISR		585.3		0.07		0.9		0.9
Crow Butte		ISR		1,135.2		0.12		2.9		2.9
Ruby Ranch		ISR		56.2		0.14		0.2		0.2
Ruth		ISR		210.9		0.08		0.4		0.4
Shirley Basin		ISR		508.0		0.10		1.1		1.1
Total				267,149.6		—		480.8		288.6

Notes

UG – underground

OP – open pit

ISR – in situ recovery

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

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

MANAGEMENT’S DISCUSSION AND ANALYSIS    89

Additional information

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

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

DECOMMISSIONING AND RECLAMATION

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

PROPERTY, PLANT AND EQUIPMENT

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

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

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

TAXES

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

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

PENSION, POST-RETIREMENT AND POST EMPLOYMENT BENEFITS

The carrying value of pensions, other post-retirement and other post-employment benefit obligations is based on actuarial valuations that are sensitive to assumptions concerning discount rates, wage increase rates, and other actuarial assumptions used. Changes in these assumptions could result in a material impact to the consolidated financial statements

90     CAMECO CORPORATION

Controls and procedures

We have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2013, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.

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

Management, including our CEO and our CFO, is responsible for establishing and maintaining internal control over financial reporting and conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2013. We have not made any change to our internal control over financial reporting during the 2013 fiscal year that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Amended and restated Bylaws

Our board has approved amended and restated bylaws for the corporation, which are now in effect, to replace bylaws approved in October 2013. Our shareholders will be asked to approve these bylaws at our 2014 annual and special meeting of shareholders. The amended and restated bylaws reflect our current practices and recommended best practices, and include an advance notice bylaw. The amended and restated bylaws will be available on our website, SEDAR and EDGAR.

The advance notice bylaw provides a transparent, structured and fair process for nominating directors under which all shareholders, whether voting by proxy or attending a meeting to elect directors, are made aware of potential proxy contests in advance of the meeting. Among other things, the advance notice bylaw fixes a deadline of not less than 30 days and not more than 65 days before a meeting of shareholders by which nominations for directors must be submitted to the corporation. We believe our shareholders should be given sufficient information and time to make appropriate decisions on the election of board representatives.

New standards and interpretations not yet adopted

A number of new standards, interpretations and amendments to existing standards are not yet effective for the year ended December 31, 2013, and have not been applied in preparing the consolidated financial statements. The following standards, amendments to and interpretations of existing standards have been published and are mandatory for our accounting periods beginning on or after January 1, 2014, unless otherwise noted.

FINANCIAL INSTRUMENTS

In October 2010, the International Accounting Standards Board (IASB) issued IFRS 9, Financial Instruments (IFRS 9). In November 2013, the IASB issued a new general hedge accounting standard, which forms part of IFRS 9. The new standard removes the January 1, 2015 effective date of IFRS 9. The new mandatory effective date will be determined once the classification and measurement and impairment phases of IFRS 9 are finalized.

This standard is part of a wider project to replace IAS 39, Financial Instruments: Recognition and Measurement (IAS 39). IFRS 9 replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The basis of classification depends on the entity’s business model and the contractual cash flow characteristics of the financial asset or liability. It also introduces additional changes relating to financial liabilities and aligns hedge accounting more closely with risk management. The mandatory effective date is not yet determined; however, early adoption of the new standard is still permitted. We do not intend to early adopt IFRS 9 in our financial statements for the annual period beginning January 1, 2014. The extent of the impact of adoption of IFRS 9 has not yet been determined.

MANAGEMENT’S DISCUSSION AND ANALYSIS    91

FINANCIAL ASSETS AND FINANCIAL LIABILITIES

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

LEVIES

In May 2013, the IASB issued International Financial Reporting Interpretations Committee (IFRIC) 21, Levies. IFRIC 21 is effective for annual periods beginning on or after January 1, 2014 and is to be applied retrospectively. IFRIC 21 provides guidance on accounting for levies in accordance with IAS 37, Provisions, Contingent Liabilities and Contingent Assets. The interpretation defines a levy as an outflow from an entity imposed by a government in accordance with legislation and confirms that an entity recognizes a liability for a levy only when the triggering event specified in the legislation occurs. We intend to adopt IFRIC 21 in our financial statements for the annual period beginning January 1, 2014. The extent of the impact of adoption of IFRIC 21 has not yet been determined.

DISCLOSURE OF RECOVERABLE AMOUNTS

In May 2013, the IASB issued amendments to IAS 36 Impairment of Assets (IAS 36). The amendments in IAS 36 are effective for annual periods beginning on or after January 1, 2014 and are to be applied retrospectively. The amendments reverse the unintended requirement in IFRS 13 to disclose the recoverable amount of every cash-generating unit to which significant goodwill or indefinite-lived intangible assets have been allocated. Under these amendments, the recoverable amount is required to be disclosed only when an impairment loss has been recognized or reversed. We intend to adopt the amendments to IAS 36 in our financial statements for the annual period beginning January 1, 2014. As the amendments impact certain disclosure requirements only, we do not expect the amendments to have a material impact on our financial statements.

92     CAMECO CORPORATION

EX-99.4

EXHIBIT 99.4

For fiscal years ended December 31, 2013 and December 31, 2012, KPMG LLP and its affiliates were paid by Cameco Corporation and its subsidiaries the following fees:

(Cdn$)	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	%

Pre-Approval Policies and Procedures

As part of Cameco Corporation’s corporate governance practices, under its committee charter, the audit and finance committee is required to pre-approve the audit and non-audit services performed by the external auditors. The audit and finance committee pre-approves the audit and non-audit services up to a maximum specified level of fees. If fees relating to audit and non-audit services are expected to exceed this level or if a type of audit or non-audit service is to be performed that previously has not been pre-approved, then separate pre-approval by Cameco Corporation’s audit and finance committee or audit and finance committee chair, or in the absence of the audit and finance committee chair, the chair of the board, is required. All pre-approvals granted pursuant to the delegated authority must be presented by the member(s) who granted the pre-approvals to the full audit and finance committee at its next meeting. The audit and finance committee has adopted a written policy to provide procedures to implement the foregoing principles. For each of the years ended December 31, 2013 and 2012, none of Cameco Corporation’s Audit-Related Fees, Tax Fees or All Other Fees made use of the de minimis exception to pre-approval provisions contained in paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X promulgated by the U.S. Securities and Exchange Commission.

EX-99.5

EXHIBIT 99.5

Contractual Cash Obligations

As at December 31, 2013 (Cdn$ millions)	Total		Due in Less Than 1 Year		Due in 1 - 3 Years		Due in 4 - 5 Years		Due After 5 Yrs
Long-term debt		1,300		—		300		—		1,000
Interest on long-term debt		481		63		111		97		210
Provision for reclamation		823		18		71		65		669
Provision for waste disposal		18		2		4		5		7
Other liabilities		46		—		—		—		46
Unconditional product purchase commitments 1, 2		1,208		352		583		109		164
Total contractual cash obligations		3,876		435		1,069		276		2,096

¹  Denominated in US dollars. Converted to Canadian dollars at the December 31, 2013 rate of Cdn $1.06.

²  Virtually all of Cameco Corporation’s product purchase obligations are under long-term, fixed-price arrangements.

Commercial Commitments

As at December 31, 2013 (Cdn$ millions)	Total amounts committed
Standby letters of credit 1		791
BPLP guarantees 2		58
Total commercial commitments		849

¹ The standby letters of credit maturing in 2014 were issued with a one-year term and will be automatically renewed on a year-by-year basis until the underlying obligations are resolved. These obligations are primarily the decommissioning and reclamation of Cameco Corporation’s mining and conversion facilities. As such, the letters of credit are expected to remain outstanding well into the future.

²  At December 31, 2013, Cameco Corporation’s total commitment for financial assurances given on behalf of BPLP was estimated to be Cdn $58 million. Refer to note 12 in the 2013 consolidated audited financial statements.

EX-99.6

EXHIBIT 99.6

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Cameco Corporation

We have audited Cameco Corporation’s internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cameco Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying management’s discussion and analysis. Our responsibility is to express an opinion on Cameco Corporation’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Cameco Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control—Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated statements of financial position of Cameco Corporation and its subsidiaries as of December 31, 2013 and December 31, 2012, and the related consolidated statements of earnings, comprehensive income, changes in equity and cash flows for the years then ended and our report dated February 7, 2014 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Chartered Accountants

Saskatoon, Canada

February 7, 2014

EX-99.7

EXHIBIT 99.7

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board Directors of Cameco Corporation

We have audited the accompanying consolidated statements of financial position of Cameco Corporation as of December 31, 2013 and December 31, 2012 and the related consolidated statements of earnings, comprehensive income, changes in equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of Cameco Corporation’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cameco Corporation as of December 31, 2013 and December 31, 2012, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Cameco Corporation’s internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 7, 2014 expressed an unqualified opinion on the effectiveness of Cameco Corporation’s internal control over financial reporting.

As discussed in Note 3 to the consolidated financial statements, Cameco Corporation has changed its method of accounting for interests in joint arrangements and employee benefits for the years ended December 31, 2013 and December 31, 2012 due to the adoption of IFRS 11 – Joint Arrangements and IAS 19R—Employee Benefits and as a result includes the presentation of the statement of financial position as at January 1, 2012.

/s/ KPMG LLP

Chartered Accountants

Saskatoon, Canada

February 7, 2014

EX-99.8

EXHIBIT 99.8

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Cameco Corporation

We consent to the use of our reports, included in this annual report on Form 40-F, each dated February 7, 2014, with respect to:

• our Auditors’ Report on the consolidated statements of financial position of Cameco Corporation (the “Corporation”) as at December 31, 2013, December 31, 2012, and January 1, 2012, the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the years ended December 31, 2013 and December 31, 2012;

• our Report of Independent Registered Public Accounting Firm in accordance with the standards of the Public Company Accounting Oversight Board (United States) on the consolidated statements of financial position of the Corporation as at December 31, 2013 and December 31, 2012, the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for the years then ended; and

• our Report of Independent Registered Public Accounting Firm on the Corporation’s internal control over financial reporting as of December 31, 2013.

We also consent to the incorporation by reference of such reports in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statement (No. 333-181577) on Form F-10.

As discussed in Note 3 to the consolidated financial statements, Cameco Corporation has changed its method of accounting for interests in joint arrangements and employee benefits for the years ended December 31, 2013 and December 31, 2012 due to the adoption of IFRS 11 – Joint Arrangements and IAS 19R – Employee Benefits and as a result, includes the presentation of the statement of financial position as at January 1, 2012.

/s/ KPMG LLP

Chartered Accountants

Saskatoon, Canada

February 27, 2014

EX-99.9

EXHIBIT 99.9

I, Tim Gitzel, certify that:

1. I have reviewed this annual report on Form 40-F of Cameco Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: February 27, 2014

/s/ Tim Gitzel
Name:	Tim Gitzel
Title:	President and Chief Executive Officer
	(Principal Executive Officer)

EX-99.10

EXHIBIT 99.10

I, Grant Isaac, certify that:

1. I have reviewed this annual report on Form 40-F of Cameco Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

5. The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: February 27, 2014

/s/ Grant Isaac
Name:	Grant Isaac
Title:	Senior Vice-President and Chief Financial Officer
	(Principal Financial Officer)

EX-99.11

EXHIBIT 99.11

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Cameco Corporation (the “Company”) on Form 40-F for the year ended December 31, 2013, as filed with the U.S. Securities and Exchange Commission on the date hereof (the “Report”), I, Tim Gitzel, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

By:	/s/ Tim Gitzel
Name: Tim Gitzel
Title:   President and Chief Executive Officer

February 27, 2014

EX-99.12

EXHIBIT 99.12

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Cameco Corporation (the “Company”) on Form 40-F for the year ended December 31, 2013, as filed with the U.S. Securities and Exchange Commission on the date hereof (the “Report”), I, Grant Isaac, Senior Vice-President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

By:	/s/ Grant Isaac
	Name:	Grant Isaac
	Title:	Senior Vice-President and Chief Financial Officer

February 27, 2014

EX-99.13

EXHIBIT 99.13

CONSENT OF EXPERT

Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.

I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:

(a) under the headings “Operations and Development Projects – Uranium Operating Properties – McArthur River/Key Lake”, “Operations and Development Projects – Uranium Operating Properties – Inkai”, “Operations and Development Projects – Uranium Development Project – Cigar Lake”, “Mineral Reserves and Resources “ and “Governance – Interest of Experts” in the Corporation’s Annual Information Form for the year ended December 31, 2013 dated February 27, 2014 for the McArthur River/Key Lake, Inkai and Cigar Lake properties; and

(b) under the headings “Our Operations and Projects—Uranium Operating Properties – McArthur River/Key Lake”, “Our Operations and Projects – Uranium Operating Properties – Inkai”, “Our Operations and Projects – Uranium Development Project – Cigar Lake” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2013 dated February 10, 2014 for the McArthur River/Key Lake, Cigar Lake and Inkai properties,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statement (No.333-181577) on Form F-10.

Sincerely,

/s/ Alain G. Mainville
Name:	Alain G. Mainville, P. Geo.
Title:	Director, Mineral Resources Management, Cameco Corporation

Date: February 27, 2014

EX-99.14

EXHIBIT 99.14

CONSENT OF EXPERT

Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.

I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:

(a) under the headings “Operations and Development Projects – Uranium Operating Properties – Inkai”, “Mineral Reserves and Resources “ and “Governance – Interest of Experts” in the Corporation’s Annual Information Form for the year ended December 31, 2013 dated February 27, 2014 for the Inkai property; and

(b) under the headings “Our Operations and Projects – Uranium Operating Properties – Inkai” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2013 dated February 10, 2014 for the Inkai property,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statement (No.333-181577) on Form F-10.

Sincerely,

/s/ Ken Gullen
Name:	Ken Gullen, P. Eng.
Title:	Technical Director, International Production, Cameco Corporation

Date: February 27, 2014

EX-99.15

EXHIBIT 99.15

CONSENT OF EXPERT

Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.

I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:

(a) under the headings “Operations and Development Projects – Uranium Operating Properties – Inkai”, “Mineral Reserves and Resources “ and “Governance – Interest of Experts” in the Corporation’s Annual Information Form for the year ended December 31, 2013 dated February 27, 2014 for the Inkai property; and

(b) under the headings “Our Operations and Projects – Uranium Operating Properties – Inkai” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2013 dated February 10, 2014 for the Inkai property,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statement (No.333-181577) on Form F-10.

Sincerely,

/s/ Lawrence Reimann
Name:	Lawrence Reimann, P. Eng.
Title:	Manager, Technical Services, Power Resources, Inc. (operating as Cameco Resources)

Date: February 27, 2014

EX-99.16

EXHIBIT 99.16

CONSENT OF EXPERT

Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.

I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:

(a) under the headings “Operations and Development Projects – Uranium Development Project – Cigar Lake”, “Mineral Reserves and Resources “ and “Governance – Interest of Experts” in the Corporation’s Annual Information Form for the year ended December 31, 2013 dated February 27, 2014 for the Cigar Lake property; and

(b) under the headings “Our Operations and Projects – Uranium Development Project – Cigar Lake” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2013 dated February 10, 2014 for the Cigar Lake property,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statement (No.333-181577) on Form F-10.

Sincerely,

/s/ Eric Paulsen
Name:	Eric Paulsen, P. Eng., Pr. Eng.
Title:	Chief Metallurgist, Technology Group, Cameco Corporation
Date: February 27, 2014

EX-99.17

EXHIBIT 99.17

CONSENT OF EXPERT

Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.

I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:

(a) under the headings “Operations and Development Projects – Uranium Development Project – Cigar Lake”, “Mineral Reserves and Resources “ and “Governance – Interest of Experts” in the Corporation’s Annual Information Form for the year ended December 31, 2013 dated February 27, 2014 for the Cigar Lake property; and

(b) under the headings “ Our Operations and Projects – Uranium Development Project – Cigar Lake” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2013 dated February 10, 2014 for the Cigar Lake property,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statement (No.333-181577) on Form F-10.

Sincerely,

/s/ C. Scott Bishop
Name:	C. Scott Bishop, P. Eng.
Title:	Principal Mine Engineer, Technology Group, Cameco Corporation
Date: February 27, 2014

EX-99.18

EXHIBIT 99.18

CONSENT OF EXPERT

Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.

I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:

(a) under the headings “Operations and Development Projects – Uranium Operating Properties – McArthur River/Key Lake”, “Mineral Reserves and Resources “ and “Governance – Interest of Experts” in the Corporation’s Annual Information Form for the year ended December 31, 2013 dated February 27, 2014 for the McArthur River/Key Lake properties; and

(b) under the headings “Our Operations and Projects – Uranium Operating Properties – McArthur River/Key Lake” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2013 dated February 10, 2014 for the McArthur River/Key Lake properties,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statement (No.333-181577) on Form F-10.

Sincerely,

/s/ Gregory M. Murdock
Name:	Gregory M. Murdock, P. Eng.
Title:	Mine Manager, Rabbit Lake, Cameco Corporation
Date: February 27, 2014

EX-99.19

EXHIBIT 99.19

CONSENT OF EXPERT

Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.

I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:

(a) under the headings “Operations and Development Projects – Uranium Operating Properties – McArthur River/Key Lake”, “Mineral Reserves and Resources “ and “Governance – Interest of Experts” in the Corporation’s Annual Information Form for the year ended December 31, 2013 dated February 27, 2014 for the McArthur River/Key Lake properties; and

(b) under the headings “Our Operations and Projects – Uranium Operating Properties – McArthur River/Key Lake” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2013 dated February 10, 2014 for the McArthur River/Key Lake properties,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statement (No.333-181577) on Form F-10.

Sincerely,

/s/ David Bronkhorst
Name:	David Bronkhorst, P. Eng.
Title:	Vice-President, Mining and Technology, Cameco Corporation
Date: February 27, 2014

EX-99.20

EXHIBIT 99.20

CONSENT OF EXPERT

Reference is made to the Annual Report on Form 40-F (the “Form 40-F”) of Cameco Corporation (the “Corporation”) to be filed with the United States Securities and Exchange Commission pursuant to the United States Securities Exchange Act of 1934, as amended.

I hereby consent to reference to my name and my involvement in the preparation of, or supervision of the preparation of, scientific and technical information in the following instances:

(a) under the headings “Operations and Development Projects – Uranium Operating Properties – McArthur River/Key Lake”, “Mineral Reserves and Resources “ and “Governance – Interest of Experts” in the Corporation’s Annual Information Form for the year ended December 31, 2013 dated February 27, 2014 for the McArthur River/Key Lake properties; and

(b) under the headings “Our Operations and Projects – Uranium Operating Properties – McArthur River/Key Lake” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2013 dated February 10, 2014 for the McArthur River/Key Lake properties,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statement (No.333-181577) on Form F-10.

Sincerely,

/s/ Leslie (Les) D. Yesnik
Name:	Leslie (Les) D. Yesnik, P. Eng.
Title:	General Manager, Key Lake operations, Cameco Corporation
Date: February 27, 2014