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, 2011 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:

394,745,423 Common Shares outstanding as of December 31, 2011

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 the end of the period covered by this report, 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, 2011.

(d) Attestation report of the registered public accounting firm. The effectiveness of Cameco Corporation’s internal control over financial reporting as of December 31, 2011 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, 2011, 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 Committee Financial Expert. Cameco Corporation’s board of directors has determined that an audit committee financial expert serves on its audit committee. The audit committee financial expert is John H. Clappison. Mr. Clappison is an “independent” director as such term is used in the rules of the New York Stock Exchange (the “NYSE”). Information concerning the relevant experience of Mr. Clappison is included in his 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

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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. In 2010, the Code was amended to add specific additional provisions addressing: (i) compliance with governmental lobbying regulations; (ii) compliance with regulatory restrictions on importing and exporting uranium; (iii) conflicts of interest between employed family members; (iv) conflicts of interest concerning Cameco Corporation’s pension plan; and (v) the identification and prevention of fraud. The Code’s confidentiality provisions were also amended to address principles contained in the Personal Information and Protection of Electronic Documents Act (Canada). The Amendments also expand the group of employees required to certify their compliance annually. Since the adoption of the Code, there have not been any waivers, including implied waivers, from any provision of the Code.

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 – 2011 Management’s Discussion and Analysis and the notes for Exhibit No 99.2 – 2011 Consolidated Audited Financial Statements:

(a) Financial assurances. In the 2011 Management’s Discussion and Analysis, see the disclosure at “Off-balance sheet arrangements” (pages 44-45). In the 2011 Consolidated Audited Financial Statements, see the disclosure at notes 16 and 31 of the financial statements.

(b) Long-term product purchase contracts. In the 2011 Management’s Discussion and Analysis, see the disclosure at “Off-balance sheet arrangements” (pages 44-45).

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 H. Clappison (chair), Daniel R. Camus, Nancy E. Hopkins, Oyvind Hushovd and A. Neil McMillan.

Audited Annual Financial Statements. Cameco Corporation’s Consolidated Audited Financial Statements as at December 31, 2011 and 2010, 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.

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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. Victor J. Zaleschuk, 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 H. F. Deranger. 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 2121-11th 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.

(e) Independent directors. The names of Cameco Corporation’s non-management directors are: Daniel R. Camus, John H. Clappison; Joe F. Colvin; James R. Curtiss; Donald H.F. Deranger; James K. Gowans; Nancy E. Hopkins; Oyvind Hushovd; A. Anne McLellan; A. Neil McMillan; and Victor J. 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 H.F. Deranger.

(f) Audit committee. John Clappison, who is the chair of Cameco Corporation’s audit committee, and Daniel R. Camus are members 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. Clappison and Mr. Camus to effectively serve on Cameco Corporation’s audit committee.

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EXHIBIT INDEX

Exhibit No.	Description
99.1	2011 Annual Information Form
99.2	2011 Consolidated Audited Financial Statements
99.3	2011 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.

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99.14	Consent of Dave Neuburger, P. Eng.
99.15	Consent of Lawrence Reimann, P. Eng.
99.16	Consent of Grant J. H. Goddard, P. Eng.
99.17	Consent of Eric Paulsen, P. Eng., Pr. Eng.
99.18	Consent of C. Scott Bishop, P. Eng.
99.19	Consent of Gregory M. Murdock, P. Eng.
99.20	Consent of David Bronkhorst, P. Eng.
99.21	Consent of Leslie (Les) D. Yesnik, P. Eng.

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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 24^th day of February, 2012.

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

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EX-99.1

EXHIBIT 99.1

Cameco Corporation

2011 Annual Information Form

February 24, 2012

Cameco Corporation

2011 Annual information form

February 24, 2012

Contents

Important information about this document	1
About Cameco	4
Operations and development projects	15
Uranium	15
Fuel services	65
Electricity	68
Mineral reserves and resources	73
Sustainable development	82
The regulatory environment	93
Risks that can affect our business	99
Legal proceedings	120
Investor information	121
Governance	127
Appendix A	132

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, 2011 (2011 MD&A), which is available on SEDAR (sedar.com) and on EDGAR (sec.gov) 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.
•	our audited consolidated financial statements for the year ended December 31, 2011 (2011 financial statements) which is also available on SEDAR and on EDGAR as an exhibit to our Form 40-F.

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.

On January 1, 2011, we adopted International Financial Reporting Standards (IFRS), which have become the generally accepted accounting principles required to be used by most Canadian publicly accountable enterprises, and we have presented financial information in this AIF in accordance with IFRS. Amounts relating to the year ended December 31, 2010 have been revised to reflect our adoption of IFRS. Amounts for periods prior to January 1, 2010 are presented in accordance with Canadian generally accepted accounting principles (Canadian GAAP) in effect prior to 2011.

The presentation and terminology used in our 2011 financial statements and this AIF differ from that used in previous years. Details of the more significant accounting differences can be found in note 3 to our 2011 financial statements.

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 99, and our 2011 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.

2011 ANNUAL INFORMATION FORM Page 1

Examples of forward-looking information in this AIF

• our expectations about 2012 and future worldwide uranium supply, consumption and demand

• production at our uranium operations in 2012 and our target for increasing annual uranium production to 40 million pounds by 2018

• our ability to maintain expected annual production at McArthur River and Key Lake

• our expectations regarding Cigar Lake

• our expectation that Inkai will receive all the necessary approvals and permits to meet its 2012 and future annual production targets

• forecasts relating to mining, development and other activities at our uranium operations

• future production at our fuel services operations

• the likely terms and volumes to be covered by long-term delivery contracts that we enter into in 2012 and future years

• future royalty and tax payments and rates

• 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

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

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

• we are unable to enforce our legal rights under our existing agreements, permits or licences, or are subject to litigation or arbitration that has an adverse outcome

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

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

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

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

• we are affected by political risks in a developing country where we operate

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

• we are affected 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, including tax and trade laws and policies

• our uranium and conversion suppliers fail to fulfill delivery commitments

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

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

• our operations are disrupted due to problems with our own or our customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, lack of tailings capacity, labour shortages, labour relations issues, 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 about the demand for uranium

• expected production levels and production costs

• expected spot prices and realized prices for uranium

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

• decommissioning and reclamation expenses

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

• geological, hydrological and other conditions at our mines

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

the additional jet boring system units we require on schedule

• our expectation that we will be able to solve technical challenges that may arise with the jet boring mining method

• 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

2011 ANNUAL INFORMATION FORM Page 2

• 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, equipment failure, labour shortages, labour relations issues, 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

2011 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.

Vision and strategy

Our vision is to be a dominant nuclear energy company producing uranium fuel and generating clean electricity. Our goal is to be the supplier, partner, investment and employer of choice in the nuclear industry.

Our strategy is to increase annual uranium production to 40 million pounds by 2018 and to invest in opportunities across the nuclear fuel cycle that we expect will complement and enhance our business. You can find more information about our strategy in our 2011 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 3,470 employees at December 31, 2011, not including Inkai.

2011 ANNUAL INFORMATION FORM Page 4

Uranium

We are one of the world’s largest uranium producers, and in 2011 accounted for about 16% 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 (U₃O ₈)

Mineral reserves and resources

Mineral reserves

• approximately 435 million pounds proven and probable

Mineral resources

• approximately 254 million pounds measured and indicated

• approximately 318 million pounds inferred

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

• McArthur River extension, Saskatchewan

• Kintyre, Australia

• Millennium, Saskatchewan

Global exploration

• focused on four continents

• approximately 5 million hectares of land

Fuel services

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

Products

• uranium trioxide (UO₃)

• uranium hexafluoride (UF₆)

  (control about 25% of world conversion capacity)

• uranium dioxide (UO₂)

  (the world’s only commercial supplier of natural UO₂)

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

Operations

• Blind River refinery, Ontario

  (refines uranium concentrates to UO₃)

• Port Hope conversion facility, Ontario

  (converts UO₃ to UF₆ or UO₂)

• Cameco Fuel Manufacturing Inc. (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

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

Electricity

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

Capacity

• 3,260 megawatts (MW) (100% basis) (about 18% 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

2011 ANNUAL INFORMATION FORM Page 5

The nuclear fuel cycle

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

1 Mining

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 the next stage of processing. 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.

2011 ANNUAL INFORMATION FORM Page 6

Major developments

2009

February

• Our $470 million bank credit facility is increased to $500 million. We cancel the facility in the third quarter.

• We add a $100 million bank credit facility. It expires in February 2012.

March

• We issue 26,666,400 common shares for net proceeds of $441 million.

April

• We enter into an Agreement on New Terms with Kyrgyzaltyn JSC (Kyrgyzaltyn) and the Government of the Kyrgyz Republic that resolves all outstanding issues regarding the Kumtor Gold mine.

June

• We resume production of UF₆ at Port Hope.

September

• We issue $500 million of 5.67% unsecured debentures due in 2019.

October

• We seal the water inflow at the 420 metre level of Cigar Lake, and resume dewatering.

December

• We dispose of our entire interest in Centerra Gold Inc. (Centerra) in two steps:

• sell 88,618,472 common shares of Centerra through a public offering for net proceeds of $871 million

• transfer another 25,300,000 common shares of Centerra to Kyrgyzaltyn, under the April 2009 Agreement on New Terms.

• Inkai commissions its main processing plant and starts commissioning its first satellite plant.

2010

February

• Inkai files a notice of potential commercial discovery at block 3. It receives approval in principle to assess commercial viability until July 2015.

• We finish dewatering the Cigar Lake mine. By year end, we resume underground development in the south end of the mine.

June

• Inkai receives approval in principle to increase annual production from blocks 1 and 2 to 3.9 million pounds (100% basis).

• We agree to supply 23 million pounds of uranium concentrate to a Chinese utility under a long-term agreement to 2020.

November

• We agree to supply 29 million pounds of uranium concentrate to another Chinese utility under a long-term agreement to 2025.

2011

January

• We begin to refreeze the ground around shaft 2.

February

• We enter into two agreements with Talvivaara Mining Company Plc. to buy uranium produced as a by-product at the Sotkano nickel-zinc mine in Finland.

• We begin to refreeze the ground around shaft 2.

March

• We restart freezing the orebody from underground at Cigar Lake.

• We complete a mineral resource estimate for our Kintyre development project.

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 and begin work on our Seru Bay project.

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 2016.

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 mill to process all Cigar Lake ore at McClean Lake.

2011 ANNUAL INFORMATION FORM Page 7

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 122 and 123.

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 four 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

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

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 2012 annual meeting of shareholders to be available in April 2012.

See our 2011 financial statements and 2011 MD&A for additional financial information.

2011 ANNUAL INFORMATION FORM Page 8

Our markets

Demand

The nuclear energy industry addressed significant challenges in 2011 related to events at the Fukushima-Daiichi nuclear power plant in Japan. On March 11, an earthquake and tsunami in Japan caused cooling systems at the Fukushima-Daiichi nuclear power plant to fail, and radioactive materials were released. This reduced public confidence in nuclear power in some countries. The outlook for the industry remains uncertain for the near to medium term. In the long-term, however, we expect demand for uranium to grow.

The demand for U₃O₈ is directly linked to the level of electricity generated by nuclear power plants.

World annual uranium fuel consumption has increased from 75 million pounds U₃O₈ in 1980 to an estimated 165 million pounds in 2011. We expect global uranium consumption to increase to about 175 million pounds in 2012. By 2021, we expect world uranium consumption to be about 230 million pounds per year, reflecting an average annual growth rate of about 3%.

We expect world demand of approximately 2.2 billion pounds over the next 10 years, which includes both world consumption and strategic inventory building. By 2021, we expect world uranium demand to be about 250 million pounds per year, an average annual growth rate of about 3%.

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 estimate world consumption of UF₆ and natural UO₂ conversion services was about 63 million kgU in 2011. We expect world consumption of UF₆ and natural UO₂ conversion services to increase by about 6% in 2012.

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).

2011 ANNUAL INFORMATION FORM Page 9

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

• 65% of global uranium supply to come from existing primary production

• 15% will come from existing secondary supply sources

• the remaining 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.

We estimate world mine production in 2011 was about 143 million pounds U₃O₈, up 2% from 140 million pounds in 2010:

• 93% of the estimated world production came from eight countries: Kazakhstan (36%), Canada (17%), Australia (11%), Niger (9%), Russia (6%), Namibia (6%), Uzbekistan (5%) and the US (3%)

• 61% of the estimated world production was marketed by five producers. We accounted for about 16% of that production (22 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 is the largest current source of secondary supply. We except deliveries from this source to end in 2013, when the Russian HEU commercial agreement expires.

• The US government makes some of its inventories available to the market, although in much 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 are also generated using excess enrichment capacity.

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 allows 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, which is expected to be completed by 2013.

This is equivalent to a total of about 400 million pounds of natural uranium as U₃O₈ (disarmament uranium). About 354 million pounds of disarmament uranium had been delivered as of the end of 2011.

Russian HEU commercial agreement

In March 1999, we and other members of a consortium of western companies 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 will receive the remaining 17 million pounds of disarmament uranium to be delivered to us under the agreement from 2012 to 2013.

Trade restraints and policies

The sale of disarmament uranium into the US market is regulated by the USEC Privatization Act, which imposes an annual quota on the sale of disarmament uranium. The 2012 quota is 20 million pounds, which is the maximum level and the same level as last year.

The US had suspension agreements with some countries that limited access to the US market, as part of uranium anti-dumping proceedings in the early 1990s. Only the suspension agreement with Russia is still in effect.

In February 2008, the US and Russia amended the agreement, allowing Russia to directly supply additional uranium

2011 ANNUAL INFORMATION FORM Page 10

to US utilities in very low annual amounts from 2011 to 2013. Russia can also supply uranium for initial cores in new US reactors. Once the Russian HEU commercial agreement ends, 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 nuclear fuel supplies from any one source to maintain security of supply (historically this was an informal level of about 20%).

Uranium from US inventories

We estimate that the US Department of Energy has an inventory of approximately 144 million pounds U₃O₈ equivalent of surplus uranium. We expect this uranium will be available to the market over the next 25 years.

In March 2008, the US Department of Energy 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). It indicated less than 3 million pounds U₃O₈ would enter the market in 2009, and that there would be a gradual rampup to 5 million pounds U₃O₈ by 2013. It also planned to make another 20 million pounds available for initial cores for new US reactors beginning in 2010. While the 20 million pounds are available, utilities may find other ways to fulfill core needs and not use this material.

In 2011, the US Department of Energy made a total of 4.2 million pounds U₃O₈ equivalent available to USEC Inc. (USEC) and another contractor, which was then made available in the spot market, in return for accelerated cleanup work at USEC’s gaseous diffusion plant in Kentucky. USEC, an American company, supplies services to enrich uranium at this plant.

In 2011, the US Department of Energy authorized the transfer of up to 1.2 million pounds U₃O₈ equivalent per quarter (up to 4.2 million pounds annually) from its uranium inventories to fund accelerated clean-up activities at the Kentucky gaseous diffusion plant. Starting with the sale of about 0.9 million pounds U₃O₈ equivalent in the first quarter of 2012, the transfers are scheduled to run until the end of the third quarter of 2013. The industry expects the US Department of Energy to adhere to its limitations, with total annual transfers under all its programs limited to 10% of the domestic US market (about 5.2 million pounds U₃O₈ equivalent).

Conversion services

We control about 25% of world UF₆ conversion capacity and we are the only commercial supplier of natural UO₂.

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 and the US. We are the only commercial supplier of UO₂ to Candu reactors operated in Canada.

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. Canada is the eighth nation to sign such an agreement with India since the Nuclear Suppliers Group lifted a 34-year ban on nuclear co-operation with India in 2008. Licensing arrangements for these exports still have to be negotiated by these two governments and discussions are ongoing.

We are in discussions with India to provide uranium for 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. Work continues to finalize the text of the

2011 ANNUAL INFORMATION FORM Page 11

protocol which will then need to be officially ratified by both countries, a process the Canadian government has indicated will take place within the next few months.

Once the protocol is ratified and the administrative arrangements are finalized, actual uranium trade can take place.

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

Our sales commitments

In 2011, 37% of our U₃O₈ sales were to five customers.

We currently have commitments to supply more than 290 million pounds of U₃O₈ under long-term contracts with 54 customers worldwide. Our five largest customers account for 47% of these commitments, and 38% of our committed sales volume is attributed to purchasers in the Americas (US, Canada and Latin America), 36% in Asia and 26% in Europe. We are heavily committed under long-term uranium contracts through 2016, so we are being selective when considering new commitments.

Our purchase commitments

We participate in the uranium spot market from time to time, including making spot purchases to take advantage of opportunities to place the material into higher priced contracts. We determine the appropriate extent of our spot market activity based on the current spot price and various factors relating to our business. In addition to being a source of profit, this activity provides insight into the underlying market fundamentals and supports our sales activities. We have also bought uranium under long-term contracts, and may do so again in the future. At December 31, 2011, we had firm commitments to buy 23 million pounds of uranium equivalent from 2012 to 2014. Seventeen of the 23 million pounds will come from deliveries under the Russian HEU commercial agreement, which runs through 2013.

Our contracting strategy

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

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

Our current uranium contracting strategy is to sign contracts with terms of 10 years or more that include mechanisms to protect us when market prices decline, and allow us to benefit when market prices go up. Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. Fixed-price contracts are typically based on the industry long-term price indicator at the time the contract is accepted, adjusted for inflation to the time of delivery. Market-related contracts may be based on either the spot price or the long-term price as quoted at the time of delivery, and often include floor prices adjusted for inflation and some include ceiling prices also adjusted for inflation.

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

The majority of our contracts include a supply interruption clause that gives us the right to reduce, on a pro rata basis, defer or cancel deliveries if there is a shortfall in planned production or in deliveries under the Russian HEU commercial agreement. We have deferred a portion of the 2012 deliveries for five years.

Our older sales contracts allow the purchaser to adjust the amount of uranium to be delivered from year to year within

2011 ANNUAL INFORMATION FORM Page 12

a specified range. Our newer contracts generally do not offer this.

Volumes and pricing

The Ux Consulting estimate for global spot market sales in 2011 is about 55 million pounds, 2% above the previous record high of 54 million pounds in 2009 and accounting for 33% of annual consumption (versus about 50 million pounds of U₃O₈ in 2010). Long-term contracting in 2011 was about 120 million pounds of U₃O₈ , compared to 250 million pounds of U₃O₈ in 2010.

The industry average spot price (TradeTech and Ux Consulting) on December 31, 2011 was $51.88 (US) per pound U₃O₈, or 17% lower than the December 31, 2010 average of $62.25 (US).

The industry average long-term price (TradeTech and Ux Consulting) was $62 (US) per pound U₃O₈ on December 31, 2011, or 6% lower than the December 31, 2010 average of $66.00 (US).

Since the nuclear incident in Japan (Fukushima), spot and term prices have experienced consistent downward pressure. Industry demand projections being revised downward and potential inventory coming to the market are the major contributing factors, prompted by immediate and expected plant closures in countries such as Germany and Japan.

Fuel services

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

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 more than 82 million kilograms of uranium under long-term contracts with 49 customers worldwide. Our five largest customers account for 37% of these commitments, and of our committed UF₆ conversion services volume, 57% is attributed to purchasers in the Americas, 24% in Asia and 19% in Europe.

Electricity business

BPLP leases and operates four Candu nuclear reactors that have the capacity to provide about 18% of Ontario’s electricity.

It receives a reliable stream of revenue from financial contracts and sells electricity on the open spot market. Spot market prices are determined by bids from suppliers and buyers that reflect changes in supply and demand by the hour. In 2011, 54% of its output was sold under financial contracts.

BPLP also trades electricity and related contracts as part of its risk management activities to hedge output against exposure to low spot prices.

Demand for electricity in Ontario has been eroding. Wholesale demand has declined significantly since 2004. Ontario demand in 2011 was down by 0.5% or 0.7 TWh compared to 2010. While this decrease signals continued inertia in the economy, we believe it will take some time for demand to return to prior levels.

BPLP has an agreement with the Ontario Power Authority (OPA) that supports output from the B reactors with a floor price (currently $50.18/MWh) adjusted annually for inflation. The floor price mechanism and any related payments to BPLP for the output from each B reactor will expire on a date specified in the agreement. The expiry dates are December 31, 2015 for unit B6, December 31, 2016 for unit B5, December 31, 2017 for unit B7 and December 31, 2019 for unit B8. Revenue is recognized monthly, based on the positive difference between the floor price and the spot price. BPLP does not have to repay the revenue from the agreement with the OPA, 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

2011 ANNUAL INFORMATION FORM Page 13

or the floor price, whichever is higher.

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.

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Operations and development projects

Uranium

Operating properties
McArthur River/Key Lake	16
Rabbit Lake	30
Smith Ranch-Highland	32
Crow Butte	33
Inkai	34
Development project
Cigar Lake	47
Projects under evaluation
Inkai blocks 1 and 2 production increase (see Inkai, above)	34
Inkai block 3 (see Inkai, above)	34
McArthur River extension (see McArthur River above)	16
Kintyre	62
Millennium	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

Electricity

Bruce Power Limited Partnership 68

Uranium production

See page 65 of our 2011 MD&A for our annual forecast of uranium production from 2012 to 2016.

Cameco’s share (million lbs U3O8)	2009		2010		2011
McArthur River/Key Lake		13.3		13.9		13.9
Rabbit Lake		3.8		3.8		3.8
Smith Ranch-Highland		1.8		1.8		1.4
Crow Butte		0.8		0.7		0.8
Inkai		1.1		2.6		2.5
Total		20.8		22.8		22.4

2011 ANNUAL INFORMATION FORM Page 15

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		226.2 million pounds (proven and probable)
(our share)		average grade U3O8 – 16.89%
Estimated mineral resources (our share)		51.0 million pounds (measured and indicated) average grade U3O8 – 17.63%
		60.3 million pounds (inferred) average grade U3O8 – 9.67%
Mining methods		currently: raiseboring pending regulatory approval: blasthole stoping under development: boxhole boring
Licensed capacity		mine and mill: 18.7 million pounds per year
		(can be exceeded – see Production below)
Total production	2000 to 2011 1983 to 2002	211 million pounds (McArthur River/Key Lake) (100% basis) 209.8 million pounds (Key Lake) (100% basis)
2011 production		13.9 million pounds (our share)
2012 forecast production		13.1 million pounds (our share)
Estimated mine life		2036 (based on current reserves)
Estimated decommissioning cost		$36.1 million - McArthur River $120.7 million - Key Lake

2011 ANNUAL INFORMATION FORM Page 16

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 530 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.

2011 ANNUAL INFORMATION FORM Page 17

Technical report

This project description is based on the project’s technical report: McArthur River Operation, Northern Saskatchewan, Canada, dated February 16, 2009 (effective December 31, 2008) 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 and one non-Cameco qualified person, 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 11 and 12, environmental matters see Sustainable development starting on page 82, and taxes see page 97.   For a description of royalties payable to the province of Saskatchewan on the sale of uranium extracted from orebodies within the province, see pages 96 and 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 one kilometre long and half a kilometre wide.

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 2014. 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, totalling 83,438 hectares, surrounding the deposit. We have title to all of these claims until 2018.

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

2011 ANNUAL INFORMATION FORM Page 18

is below -20°C, and winter daily temperatures can reach below -40°C.

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, and consist of two distinct parts:

• a hanging wall pelitic sequence of cordierite and graphite bearing pelitic and psammopelitic gneiss with minor meta-arkose and calc-silicate gneisses

• a sequence consisting of quartzite and silicified meta-arkose and rare pelitic gneisses.

These are unconformably overlain by flat lying, unmetamorphosed 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. The sandstone is 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.

There are four zones of delineated mineral reserves (zones 1 to 4). Six zones contain mineral resources (zones A and B and parts of zones 1, 2, 3 and 4). The width of the ore varies. The main part of the orebodies, 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 orebodies ranges from 50 metres to 120 metres.

Zone 2 is divided into four panels (panels 1, 2, 3 and 5). Panel 5 represents the upper portion of zone 2, overlying part of the other panels.

Five of the six mineralized zones are in sandstone and basement rock along the faulted edge of the basement wedge. Zone 2 sits in structurally disrupted 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.

2011 ANNUAL INFORMATION FORM Page 19

About the McArthur River mine

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

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.

Our mine production comes from zone 2 panels 1, 2, 3 and 5 and the lower area of zone 4. We started mining the lower area of zone 4 at the end of 2010. In 2011, we began production from the second raisebore chamber in zone 2, panel 5.

Permits

We need three permits to operate the McArthur River mine:

• Uranium Mine Facility Operating Licence – renewed in 2008 and expires on October 31, 2013 (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)

• Permit to Operate Waterworks – renewed in 2011 and expires on April 30, 2012 (from the Saskatchewan Ministry of Environment).

2011 ANNUAL INFORMATION FORM Page 20

Infrastructure

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

• an underground mine with three shafts:

one to move workers, material and waste rock and for fresh air ventilation, one for mine exhaust air ventilation, and one for fresh air ventilation and an emergency exit

• waste rock stockpiles

• a minewater treatment plant and ponds

• a freshwater pump house

• a powerhouse

• electrical substations

• standby electrical generators

• maintenance and warehousing facilities

• freeze plant

• a concrete batch plant

• an administration building

• a workforce residence

• an ore loadout building.

Water, power and heat

Toby Lake, which is nearby and easy to access, has enough water to satisfy all 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.

In 2009, we developed an innovative, cathedral-shaped freezewall around zone 2, panel 5, allowing us to develop tunnels above and below the orebody. We expect this innovation will allow us to continue using raisebore mining as the main mining method at McArthur River and improve production efficiencies as we transition to other areas of the mine.

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 ore

• 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

• filling each raisebore hole with concrete once mining is complete

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

• starting the process again with the next raisebore chamber.

We have successfully used the raisebore mining method to extract about 210 million pounds (100% basis) since we began mining in 1999.

We may also use boxhole boring and blasthole stoping in other areas of the mine.

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Blasthole stoping

Blasthole stoping involves establishing drill access above the ore and extraction access below the ore. The area between the upper and lower access levels (the stope) is then drilled off and blasted. The broken rock and ore are 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 for mining uranium.

Blasthole stoping is being evaluated for the recovery of small isolated, lower grade ore zones away from the freezewalls and where raisebore or boxhole boring is uneconomic or impractical. We mined our first blasthole stope in the fourth quarter of 2011, in lower zone 4, with good productivity.

We plan to test the method again in 2012.

Boxhole boring

Given our success with the cathedral-shaped freezewall around zone 2, panel 5, the use of boxhole boring in our mine plan has been significantly narrowed in scope. We expect to be able to continue using raisebore mining as our main mining method for McArthur River.

Boxhole boring is similar to the raisebore method, but the drilling machine is located below the orebody, so development is not required above the orebody. This method is currently being used at only a few mines around the world, but has not been used for uranium mining.

Boxhole boring poses some technical challenges. We have completed four test raises in waste, and plan to complete four test raises in ore in 2012. However, we expect it will only be used as a secondary method, in areas where we determine raiseboring is not feasible. Boxhole boring may not be as productive as the raisebore method, but we will be able to determine this more accurately once we have fully developed and tested the method at McArthur River.

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, which ranges in grade from 15 to 30% uranium, is pumped into transport truck containers and shipped to Key Lake mill on an 80 kilometre all-weather road.

Contaminated water from this process, including water from underground operations, is treated on the surface. The extra treated water we do not need 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.

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.

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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.

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.

Production

• Forecast: 18.7 million pounds of U₃O₈ per year until 2020 (our share will be 13.1 million pounds). After that, it declines until 2036.

• 2011: 20 million pounds of U₃O₈ was produced by milling McArthur River ore at Key Lake (our share was 13.9 million pounds). Average mill metallurgical recovery was 98.7%.

In 2010, the CNSC approved an amendment to our operating licence for McArthur River, giving us flexibility in the annual licensed production limit, similar to that received at Key Lake in 2009. The McArthur River mine can produce up to 21 million pounds (100% basis) per year as long as average annual production does not exceed 18.7 million pounds. If production is lower than 18.7 million pounds in any year, we can produce more in future years until we recover the shortfall. We still have the opportunity to recover about 3.5 million pounds (100% basis) in past production shortfalls.

Recent activity

In 2011, we continued mining the lower mining area of zone 4. We removed abandoned freeze pipes from the new production chamber and began production from the second raisebore chamber in zone 2, panel 5. We have completed production from the first chamber and are developing the third through draft and fill.

In 2012, we will continue the drilling to install the freezewall required to bring the upper mining area of zone 4 into production. We expect to start freezing upper zone 4 in 2013 and begin production from this area 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 addition to the exploration work discussed below, we advanced feasibility work on the McArthur River extension project this year. This is a multi-year project to safely expand the underground mine and develop new mining areas. Our plan is to:

• increase average annual production at the mine from 18.7 million pounds (100% basis) to 22 million pounds (100% basis)

• construct the infrastructure necessary to support production at this level

• further delineate mineral resources to the north and south of the current mining operations.

An environmental assessment is required for the potential increase in production. Other work on this project will be approved through regular licensing activities.

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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 three permits to operate the Key Lake mill:

• Uranium Mine Facility Operating Licence – renewed in 2008 and expires on October 31, 2013 (from the CNSC)

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

• Permit to Operate Waterworks – renewed in 2009 and expires on November 30, 2014 (from the Saskatchewan Ministry of Environment)

In June 2009, the CNSC amended our operating licence for Key Lake, giving us flexibility in annual licensed production. The Key Lake mill can produce up to 20.4 million pounds U₃O₈ per year as long as average annual production does not exceed 18.7 million pounds. If production is lower than 18.7 million pounds in any year, we can produce more in future years until we recover the shortfall. We still have the opportunity to recover about 2.5 million pounds (100% basis) in past production shortfalls. This also gives us the flexibility to avoid having to restart the mill in cold winter temperatures.

After the mill is revitalized, annual production will depend mainly on mine production. We are continuing to plan for 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 17 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.

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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.

• 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).

At current production rates, the licensed capacity of the Deilmann TMF is about six years, assuming only minor losses in storage capacity because of sloughing from the pitwalls. Significant sloughing may constrain McArthur River production.

In the past, sloughing of material from the pitwalls has reduced tailings capacity. Studies show that stabilizing and reducing water levels in the pit enhances the stability of the pitwalls, which reduces the risk of pitwall sloughing. We have doubled our dewatering treatment capacity, allowing us to stabilize the water level in the pit. This water level has been reduced gradually over the past three and a half years.

In 2009, regulators approved our plan for the long-term stabilization of the Deilmann TMF pitwalls. We are implementing the plan, and expect it will take approximately three years to complete the work.

In 2011, we:

• completed the detailed design for the stabilization of the Deilmann TMF pitwalls

• relocated the infrastructure necessary to allow us to flatten the slope of the pitwalls

• continued our work on the environmental assessment for the Key Lake extension project.

In 2012, we expect to:

• begin to flatten the slope of the Deilmann TMF pitwalls

• advance the environmental assessment for the Key Lake extension project. We plan to submit the draft environmental impact statement to the regulators by the end of the second quarter. Comments on the draft are expected before year end.

We have assessed options for long-term storage of tailings at Key Lake. We 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. Once we receive approval, this would provide us with enough tailings capacity to potentially mill a

2011 ANNUAL INFORMATION FORM Page 25

volume equal to all the known mineral reserves and resources from the McArthur River operation and additional capacity to toll mill ore from other regional deposits.

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. Our initial work is in three areas:

• operational upgrades – upgrading circuits with new technology to simplify operations, increasing annual production capacity and improving environmental performance. As part of this plan, we replaced the acid, steam and oxygen plants. At the end of 2011, construction of all three plants was complete. The steam plant was commissioned at year end and the oxygen plant was commissioned in early 2012. We have started commissioning the acid plant. Also, foundations are being installed so a new electrical substation and calciner can be installed.

• treatment of effluent – completed

• increase in tailings capacity – see Tailings capacity, above.

We may make other changes to the mill, depending on the results of studies.

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. These documents include our estimated cost for implementing the decommissioning plan and addressing known environmental liabilities.

We, along with our joint venture partner, posted letters of credit as financial assurances with the Saskatchewan Ministry of the Environment to cover the amounts in the 2008 preliminary decommissioning cost estimates ($36.1 million for McArthur River and $120.7 million for Key Lake).

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 1,700 metres at 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 1,000 drillholes and 185,000 metres. Drilling has been carried out from both surface and underground in order to delineate and locate mineralization. Surface exploration drilling is initially used in areas where underground access is not available and is used to guide the underground exploration programs. Drilling to date has identified mineral reserves and resources over a strike length of 1.8 kilometres and in six main zones (zones 1 to 4 and zones A and B).

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 north and south of the mine. Surface drilling has been over a strike length of two kilometres, generally at between 500 metres to 640 metres below the surface.

As of December 31, 2011, we had drilled 145 surface drillholes (both conventional and directional drilling) for a total of over 85,000 metres along the P2 trend. This includes 13 drillholes totaling approximately 6,800 metres, completed during 2009 to confirm and further delineate the zone B resource.

We have completed preliminary drill tests of the P2 trend at 200 metre intervals over 11.2 kilometres (4.3 kilometres north and 6.9 kilometres south of the McArthur River mine site) of the total 14.8 kilometres strike length of the P2 trend. A total of $5.0 million (our share $3.49 million) has been budgeted in 2012 for diamond drilling to follow up on any anomalies in 2011 and continue systematic testing of the P2 trend south of the mine.

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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 850 underground drillholes since 1993, over 78,000 metres, to get detailed information along 750 metres of the surface delineation, and used this data to estimate the mineral reserves and resources in four mineralized zones (zones 1 to 4). The drilling was 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 (the southern part of the deposit, and in zones A and B in the northern 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 and geotechnical programs. To date, we have drilled over 900 holes along more than 50,000 metres under these programs.

Recent activity

We initiated a multi-year project, the McArthur River extension, in 2010, to advance the underground exploration drifts on the 530 metre level to the north and to the south of the current mining operations. We began tunneling the north exploration drift in 2007, and the south exploration drift in 2010.

In 2011, we advanced the exploration drifts to zones A and B, north of current mining operations, and were successful in upgrading the majority of the zone B inferred mineral resources to the indicated category based on surface drilling. This area continues to show promise.

In 2012, we plan to continue advancing the underground exploration drift to the south of the current mining areas. We also plan to test, from surface, along the entire length of the mineralized zone to identify additional mineral resources.

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

2011 ANNUAL INFORMATION FORM Page 27

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.

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.

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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 seven years, actual annual uranium production has been within 5% of our estimates.

Mineral reserve and resource estimates

Please see page 73 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	24.0 million pounds (proven and probable) average grade U3O8 – 0.73%
Estimated mineral resources	4.3 million pounds (indicated) average grade U3O8 – 0.53%
	10.4 million pounds (inferred) average grade U3O8 – 1.42%
Mining method	vertical blasthole stoping
Licensed capacity	mill: maximum 16.9 million pounds per year; currently 11 million
Total production 1975 to 2011	186.3 million pounds
2011 production	3.8 million pounds
2012 forecast production	3.7 million pounds
Estimated mine life	2017 (based on current reserves)
Estimated decommissioning cost	$105.2 million

Business structure

We own 100% of Rabbit Lake.

Permits

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

• Uranium Mine Operating Licence from the CNSC

• Approval to Operate Pollutant Control Facilities from the Saskatchewan Ministry of the Environment

• Permit to Operate Waterworks from the Saskatchewan Ministry of the Environment.

These permits expire on October 31, 2013.

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Production

2011 production was 3.8 million pounds U₃O₈, the same as it was in 2010.

Operations

During our scheduled mill maintenance shutdown in the third quarter of 2011, we completed the second phase of upgrades at the acid plant, successfully replacing the acid plant final towers.

Exploration

In 2010, we added mineral reserves, extending the estimated mine life by two years to 2017.

In 2011, we received regulatory approval to begin exploration–related development and drilling on the Powell Zone, and completed a portion of the development work. We plan to complete the development work in 2012 and carry out drilling to further evaluate this zone.

We have extended our underground drilling reserve replacement program into 2012. We plan to test and evaluate areas east and northeast of the mine where we have had good results, and to the north and south. The drilling will largely be from surface.

Tailings

We expect the mill to have the capacity to handle tailings from milling ore from Rabbit Lake until approximately mid-2016 (based on expected ore grades and milling rates).

We are planning to expand the existing tailings management facility by mid-2016 to increase the tailings capacity so that it can support the extension of Rabbit Lake’s mine life, and provide additional tailings capacity to process ore from other potential sources. We need regulatory approval to proceed with any increase in capacity and will pay the resulting capital costs. The increase in tailings capacity will require an environmental assessment.

Site reclamation

We are proceeding with our multi-year, site wide reclamation plan. We spent over $10 million in 2011 to reclaim facilities that are no longer in use, and plan to spend over $2 million in 2012.

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.

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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 processes all the uranium. 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	6.6 million pounds (proven and probable) average grade U3O8 – 0.09%
Estimated mineral resources	23.7 million pounds (measured and indicated) average grade U3O8 – 0.06%
	6.6 million pounds (inferred) average grade U3O8 – 0.05%
Mining method	in situ recovery (ISR)
Licensed capacity	wellfields: 2 million pounds per year processing plants: 5 million pounds per year including Highland mill
Total production 2002 to 2011	15 million pounds
2011 production	1.4 million pounds
2012 forecast production	1.7 million pounds
Estimated decommissioning cost	$168 million (US)

Business structure

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

See our 2011 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	3.7 million pounds (proven) average grade U3O8 – 0.13%
Estimated mineral resources	11.9 million pounds (indicated) average grade U3O8 – 0.21%
	6.0 million pounds (inferred) average grade U3O8 – 0.12%
Mining method	in situ recovery (ISR)
Licensed capacity (processing plant and wellfields)	1 million pounds per year
Total production 2002 to 2011	7.6 million pounds
2011 production	0.8 million pounds
2012 forecast production	0.7 million pounds
Estimated decommissioning cost	$35.6 million (US)

Business structure

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

See our 2011 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
ISO certification	BSI OHSAS 18001
	ISO 14001 certified
Estimated mineral reserves (our share)	59.7 million pounds (proven and probable) average grade U3O8 – 0.07%
Estimated mineral resources (our share)	28.8 million pounds (indicated) average grade U3O8 – 0.08%
	153 million pounds (inferred) average grade U3O8 – 0.05%
Mining method	in situ recovery (ISR)
Licensed capacity (wellfields)	approved: 3.9 million pounds per year (our share 2.3 million pounds per year)
	application: 5.2 million pounds per year (our share 2.9 million pounds per year)1
Total production 2008 to 2011	6.5 million pounds (our share)
2011 production	2.5 million pounds (our share)
2012 forecast production	2.5 million pounds (our share) 1
Estimated mine life	2030 (based on current reserves)
Estimated decommissioning cost	$11 million (US)

¹  For more information on the application to increase the licensed capacity at Inkai and our share of production, see Production increases for 2011, 2012 and 2013.

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)

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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 -	•	Kazatomprom is established
1998	•	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)

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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 David Neuburger, P. Eng., Alain G. Mainville, P. Geo 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 Sustainable development starting on page 82.   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 97 and 98.

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 Kyzl-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 gravel road and crosses the Karatau Mountains. Railroad transportation is available from Almaty to Shymkent, then northwest to Shieli, Kyzl-Orda and beyond. A rail line also runs from the town of Dzhambul 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 40 and 41 for more information.

Setting

Inkai lies in the Betpak Dala Desert, which has an arid climate, minimal precipitation and relatively high evaporation. The surface elevation ranges from 140 to 300 metres above mean sea level. The average precipitation varies from 130 to 140 millimetres per year, and 22 to 40% of this is snow.

The area also has strong and almost uninterrupted winds that travel from 3.8 to 4.6 metres per second. The prevailing winds are northeast. Dust storms are common. 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

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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.

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 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. Inkai requires regulatory approval of the detailed block 3 delineation and teach leach work programs.

In 2012, Inkai expects to continue delineation drilling and advancing development of the test leach facility.

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

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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

We need 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 works connected with stages of life cycle of objects of use of atomic energy (issued January 18, 2010 by the Kazakhstan Ministry of Energy and Mineral Resources (MEMR))

• 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 substances (issued August 29, 2008 by the MEMR)

These licences are all currently in force and have an indefinite term. Inkai’s material environmental permits are described on page 41.

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 We are planning an expansion of the satellite processing plant.	We are engineering a test leach facility.

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. In 2007, a fire at a sulphuric acid plant in Kazakhstan, and delays in the start-up of a new plant, restricted the availability of sulphuric acid. Allotments of sulphuric acid to Inkai and other ISR operations in Kazakhstan were reduced. The shortage continued throughout 2008, though it was resolved by the end of that year. Inkai received enough sulfuric acid in 2009 and 2010 to acidify the wellfields as planned.

During 2011, Inkai experienced brief interruptions to its sulphuric acid supply, which had a small impact on production. The supply of sulphuric acid is tight in Kazakhstan. Given the importance of sulphuric acid to Inkai’s mining operations, 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 99.5 million pounds U3O8 (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 planning to expand the existing satellite plant capacity in order to support this production rate from lower grade solution. Regulatory approval is required to carry out production at the annual rate of 5.2 million pounds per year (100% basis). See Production increases for 2011, 2012 and 2013.

Production increases for 2011, 2012 and 2013

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

In August 2011, we entered into a non-binding memorandum of agreement 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 memorandum of agreement, 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.

Our 2012 and future annual production targets and mineral reserve estimate for Inkai assume and we expect:

• Inkai will obtain the necessary government permits and approvals to produce at an annual rate of 5.2 million pounds (100% basis), including an amendment to the resource use contract

• we reach a binding agreement with Kazatomprom to finalize the terms of the memorandum of agreement

• Inkai will ramp up production to an annual rate of 5.2 million pounds (100% basis).

There is no certainty Inkai will receive these permits or approvals or we will reach a binding agreement with Kazatomprom or that Inkai will be able to ramp up production. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2012 and future annual production targets and we may have to recategorize some of Inkai’s mineral reserves as resources.

As part of our strategy to increase annual production to 40 million pounds by 2018, we are working with our partner, Kazatomprom, to implement our 2007 non-binding memorandum of understanding.

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The memorandum:

• targets future annual production capacity at 10.4 million pounds (100% basis). Our share of the additional capacity is expected to be 50%.

• contemplates studying the feasibility of constructing a uranium conversion facility, as well as other potential collaborations in uranium conversion.

To implement this increase, we need a binding agreement to finalize the terms of the memorandum and various approvals from our partner and the government. We are currently in discussions with Kazatomprom about these initiatives. We expect our ability to double annual uranium production at Inkai will be closely tied to the success of the uranium conversion project.

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 one forward uranium sales contract for a portion of its 2012 production, and it is with us.

Funding

We have a loan agreement with Inkai. As of December 31, 2011, there was:

• $192 million (US) of principal outstanding on the loan (in 2011 Inkai repaid $122 million (US) of principal)

• a nominal amount of accrued interest and financing fees on the loan. In 2011, Inkai paid $6 million (US) in accrued interest and financing fees.

Inkai uses 100% of the cash available for distribution each year to pay accrued interest and financing fees. After those amounts are paid, Inkai uses 80% of cash available for distribution each year to repay principal outstanding on the loan until it is repaid in full. The remaining 20% of cash available for distribution is paid to the owners.

We have also agreed to advance funds for Inkai’s work on block 3 until the feasibility study is complete.

Costs and payback

In the March 2010 technical report:

• capital costs remaining were estimated to be $359.2 million (US). This includes $208.6 million (US) for wellfield development. We expect wellfield development costs to decline gradually over the last five years of production.

• payback was forecast in 2012, on an undiscounted, after-tax basis, including all 2009 and 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.

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In April of 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.

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). The work plan will need to be updated and submitted to the relevant government authority whenever a change is made.

Prior to the new subsoil law, Inkai had to submit an annual work plan to the government authority every year for approval.

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.

Under Kazakhstan law, Inkai needs an environmental permit to operate. Inkai has a permit for environmental emissions and discharges, valid until December 2013, and an emissions permit for drilling activities, valid until December 2012. It 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 $11 million (US).

Groundwater is not actively restored post-mining in Kazakhstan. See page 85 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.

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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.

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.

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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 is revising its work program to support an application to increase the annual production rate to 5.2 million pounds (100% basis).

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.

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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.

• 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, 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 2,603 exploration holes in block 3 as of the end of December 2011 (510 historic holes drilled before 2006, 45 in 2006, 90 in 2008, 456 in 2009, 1,008 in 2010 and 494 in 2011). 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 28 hydrogeological test wells were drilled in 2010 and 2011.

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. 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 and 2011 in the southwestern part 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

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• 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

• identified two sites for conducting ISR tests in two separate horizons (Inkuduk and Mynkuduk) and an ISR test work technical project package is being prepared.

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 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)

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

Quality control

• Our geoscientists have witnessed core handling, logging and sampling used at the Inkai mine and considers the methodologies to be very satisfactory and the results representative and reliable.

• Geologists with Inkai, 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.

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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 73 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 McClean Lake.   Cigar Lake, which is being developed, is one of our three material uranium properties.

Location	Saskatchewan, Canada
Ownership	50.025%
End product	uranium concentrates
Mine type	underground
Estimated mineral reserves (our share)	108.4 million pounds (proven and probable) average grade U3O8 – 18.30%
Estimated mineral resources (our share)	1.1 million pounds (measured and indicated) average grade U3O8 – 2.25% 62.2 million pounds (inferred) average grade U3O8 – 12.59%
Mining method	jet boring
Target production date	begin commissioning in ore in mid-2013 first packaged pounds in the fourth quarter of 2013
Target annual production (our share)	9 million pounds at full production
Estimated mine life	15 years (based on current mineral reserves)
Estimated decommissioning cost	$27.7 million (to the end of construction)

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 (which is under construction) 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, and establish safe access to the 480 metre level, the main working level of the mine
	•	We substantially complete cleanup, inspection, assessment and securing of underground development and resume underground development in the south end of the mine
	•	We backfill the 465 metre level
2011	•	We begin to freeze the ground around shaft 2 and restart freezing the orebody from underground
	•	We begin freezing the orebody 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

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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).

The conclusions, projections and estimates included in this description are subject to the qualifications, assumptions and exclusions set out in the technical report. 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).   The report was prepared for us in accordance with NI 43-101, by or under the supervision of C. Scott Bishop, P. Eng, Grant J.H. Goddard, 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 11 and 12, environmental matters see Sustainable development starting on page 82, and taxes see page 97.   For a description of royalties payable to the province of Saskatchewan on the sale of uranium extracted from orebodies within the province, see pages 96 and 97.

About the property

Location

Near Waterbury Lake, 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. We have title to all of these claims 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 that 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.

The deposit consists mainly of three dominant rock and mineral facies in varying proportions: quartz, clay (primarily chlorite with lesser illite) and metallic minerals (oxides, arsenides, sulphides). In the eastern part of the deposit (Phase 1), the ore is 50% clay matrix, 20% quartz and 30% metallic minerals, visually estimated by volume, overlain by a very weak mineralized clay cap one to five metres thick. In the lower-grade western part of the deposit (Phase 2), the proportion changes to 20% clay, 60% quartz and 20% metallic minerals.

About the operation

Cigar Lake is a development project with sufficient surface rights to meet future mining operation needs for the current mineral reserves.

Permits

Please see page 58 for more information about regulatory approvals for Cigar Lake.

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Infrastructure

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

•    an underground mine with one shaft constructed and one shaft under construction   •    waste rock stockpiles   •    ore slurry load out building (substantially completed)   •    contingency ponds   •    water treatment ponds   •    water treatment plant   •    temporary administration building •    construction camp   •    freeze plant   •    sewage lagoon   •    an employee residence   •    gravel airstrip and terminal   •    electrical substations and powerhouse   •    fuel and propane supply, storage and distribution facilities.

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.

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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. Bulk freezing reduces but does not eliminate the risk of water inflows.

In the past, bulk freezing has been done from underground. In 2010, however, we tested and began to implement an innovative surface freeze strategy, which we expect will provide the following benefits:

• reducing risk to the construction schedule in two ways: (i) the surface freeze process can start before developing the underground tunnels; and (ii) the construction activities underground are simplified by moving some of the related freezing activities and infrastructure to surface

• contributing positively to overall project economics.

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. 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.

Also in 2011, we used freezing around shaft 2 to support the sinking and in early 2012 we broke through on the 480 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 is new to the uranium mining industry. It 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.

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 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 testing, pre-commissioning, commissioning and startup plan has been implemented to assure successful startup and on-going operations. We are confident we will be able to solve challenges that may arise, but failure to do so would have a significant impact on our business.

Our mining plan requires four jet boring system units. We currently have one unit and in 2011, we signed an agreement with a European based, global mining and tunnelling equipment supplier to manufacture and supply three additional jet boring system units. We plan to procure additional equipment for the jet boring system in 2012. 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 three additional units does not take place as scheduled. As part of our startup plan noted above, we are working with our supplier to assure timely delivery of these units.

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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. Construction of these facilities is in progress.

Both mine development for construction and operation uses two basic development systems: drill and blast with conventional ground support, and mine development system, a 5.1 metre diameter full face tunnel boring machine, which installs a precast concrete tunnel lining for ground support. We are evaluating the use of a roadheader excavator for those areas of weak ground away from the orebody.

With the exception of the mine development system headings, the infrastructure excavations and the access drifts are being constructed using conventional drill and blast mining methods. Geotechnical drilling and analysis of ground conditions is completed prior to confirming permanent infrastructure locations.

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 minesite 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. We have not identified any mineralized waste in development to date

• 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 is currently treated and released to Aline Creek. In 2011, we received approval to change the discharge location to Seru Bay (see page 58). Completion of construction and subsequent operating approvals from the CNSC and the province of Saskatchewan are expected in 2012. We expect to begin discharging treated water directly to Seru Bay in mid-2012, as planned, once the construction of the pipelines and associated infrastructure is completed.

Production

We updated the mining plan after the two mine in-flows, and expect commissioning in ore to begin in mid-2013, with the first pounds to be packaged at the McClean Lake JEB mill in the fourth quarter of 2013. The mining plan is designed to extract all of the current mineral reserves. The following is a general summary of the production schedule

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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%
	•	Rampup to full production rate by the end of 2017
	•	Full annual production of 18 million pounds by 2018 (less than this in the early and late years of the current mineral reserve life)
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

To meet our production schedule, the ground has to be fully frozen in the area being mined before we start jet boring mining.

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 any one time two jet boring machines will be jetting (producing ore) while the other two are in the process of moving/setting up, or in the backfill cycle.

Payback

In the February 2012 technical report, we estimated payback, on an undiscounted pre-tax basis, in 2017. This did not include all construction costs spent on Cigar Lake prior to 2012, including remediation costs.

Costs

As of December 31, 2011, we had:

• invested about $675 million for our share of the construction costs to develop Cigar Lake

• expensed about $86 million for our share of remediation expenses, including about $4 million in 2011

• expensed about $35 million for our share of standby costs.

We expect to spend an additional $484 million (our share) to complete this project, which requires us to:

• invest about $429 million for our share of the remaining capital costs, bringing our total share to about $1.1 billion

• expense about $55 million for our share of the remaining standby costs, bringing our total share to about $90 million.

This would bring our total share of the cost for this project to about $1.3 billion since 2004.

	Cameco’s share of costs ($ millions)
Cost area description	2004-2011		2012-2015		Total (100%)
Capital costs		675		429		1,104
Remediation costs		86		—		86
Standby costs		35		55		90
Total costs		796		484		1,280

Forecasts of costs, production, 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.

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Assumptions

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

• there are no labour disputes or shortages

• all necessary contractors, equipment, operating parts, supplies, regulatory permits and approvals are obtained when they are needed

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

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

• our Cigar Lake development, mining and production plans succeed

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

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

Material risks

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

• ground movements and cave ins

• necessary regulatory permits or approvals cannot be obtained or maintained

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

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

• our mineral reserves estimate is not reliable

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

Assurance of success program

We adopted an assurance of success program for Cigar Lake that uses risk-based quality assurance planning. This involves carrying out a thorough assessment of the risks associated with all principal processes before implementation, with a goal of making sure we understand all the risks, have measures in place to mitigate them, and alternate plans to address any risks that cannot be fully mitigated. We regularly monitor and evaluate any changes or conditions that we did not anticipate in our original plan, assess any new risks and then update the plan.

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. 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, posted letters of credit as financial assurances with the Saskatchewan Ministry of Environment in the amount of $27.7 million, to cover these costs.

As part of our operating licence application, we will review the plan and cost estimate and update them to account for changes in our decommissioning liabilities.

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.

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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.

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

We completed the dewatering of shaft 2 in April 2009 and remediation was completed in May 2009. The freezing infrastructure to support the completion of shaft sinking was completed in early 2011 and the freeze system activated. Shaft sinking resumed in the first half of 2011 and by early 2012, we had achieved breakthrough to the 480 metre level and sinking to completion (the 500 metre level) continues. The breakthrough to the 480 metre level provided for a second means of egress for the mine and for increases in ventilation.

In 2011, a hydrostatic liner was installed in the shaft from the 368 metre depth to the 480 metre level, where it will transition back to a non-hydrostatic liner.

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We plan to complete shaft 2 by the second quarter of 2013, taking the following steps:

• sinking the shaft from the current shaft bottom depth of 480 metres to its final depth of 500 metres – to be completed in 2012

• establishing a shaft station at the 480 metre level

• installing shaft furnishings including construction of a concrete ventilation partition, installation of electrical cable, water services, ore slurry pipes and permanent service cage facilities

• commissioning of the shaft systems.

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 2009, we received interim approval to release up to 1,100 m³/hr of treated water in non-routine circumstances, to accommodate remediation activities in the mine. In 2011, we received approval to allow direct discharge of treated water to Seru Bay of Waterbury Lake which is intended to increase the mine’s dewatering capacity, and then approval to proceed with construction. Completion of construction and subsequent operating approvals from the CNSC and the Province of Saskatchewan are expected in 2012. As of early 2012, our mine dewatering capacity has increased to 2,500 m³/hr and our mine water treatment capacity has been 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

We began construction on the Seru Bay infrastructure project in 2011, and completed several surface facilities by the end of the year. Surface construction at Cigar Lake is 56% complete. Important surface construction still remaining includes the new administration/services building, the Seru Bay pipeline, completion of the surface ore process facilities and the new propane tank farm, and expansion of the 138 kilovolt electrical substation and the permanent employee residence.

Underground development

We estimate that the underground development necessary to start production is 70% complete.

Toll milling agreement

Milling the slurry from the Cigar Lake mine is a two-step process:

• processing the ore slurry into JEB uranium solution

• processing the JEB uranium solution into uranium concentrates.

The McClean Lake mill will carry out this work according to the terms of a toll milling agreement.

McClean Lake JEB 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. Standby costs of $22 million were expensed in 2011 with the JEB mill placed in a care and maintenance mode in July 2010. We estimate our share of further standby costs to be about $55 million. These costs will be expensed as incurred, and are not included in the project’s capital cost.

A number of mill modifications have been completed to date at the JEB mill to process Cigar Lake ore. Under the memorandum of agreement, the McClean Lake joint venture is required to further modify and expand the JEB mill to

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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. Construction of the expanded facility is scheduled to begin in 2012 and be completed in 2015. Mill operation will continue during the construction stages in order to meet the Cigar Lake production schedule.

The McClean Lake joint venture plans to commence 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 now expires on December 31, 2013. The second extension was provided to give us time to complete mine construction, including remediation, sinking shaft 2 and surface construction.

• In 2011, we received approval for additional licence activities including our revised mine plan allowing for completion of remediation and resumption of pre-flood underground construction and development activities.

• In early 2012, we received approval for the establishment of shaft 2 as a second means of egress.

Operating licence

While we are completing mine construction, we will be preparing an operating licence application for submission to the CNSC. This licensing process can proceed while construction is being completed.

Processing licences

• An amendment is required to the McClean Lake JEB mill licence to process Cigar Lake ore at the McClean Lake JEB mill. We do not anticipate any issues with the amendment to the licence. 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. We have interim approvals and measures in

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place to increase discharge to the Aline Creek system if we need to prior to the Seru Bay discharge point being operational. We require further operating approvals from the CNSC and the Province of Saskatchewan, which we expect in 2012.

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 406 surface holes have been drilled totalling 178,255 metres. 215 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

Additional delineation drilling is planned over Phase 2 as well as freezehole drilling over Phase 1 in 2012.

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 210 metres in strike length and 30 metres in across-strike length. Additional drilling is planned for this mineralization in 2012.

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 totalling 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 – 2011	90 holes were drilled underground totalling 8,453 metres. None intersected the deposit. 5 of the 90 holes were drilled from inside shaft 2, in advance of the top seal grout cover. 74 holes were drilled from the 480 metre level and the remaining 11 holes were drilled from the 500 metre level.

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

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.

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

Samples were drawn from two phases of the deposit:

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

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

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

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

• 30 infill drillholes were completed in 2011 for select areas of the western part of the Phase 2 deposit, which locally reduced the drillhole spacing down to a 15 metre by 15 metre pattern. These holes have not been included in the current resource estimate as drilling is ongoing in 2012.

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.

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

Analysis

• More than 5,400 samples were assayed 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.

• 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.

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

• Most of the underground drillholes 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.

• Chemical assays were used to determine grade in mineralized rock.

• Core recovery through the ore zone has generally been very good. Where necessary, uranium grade determination is supplemented by down-hole radiometric probing results.

• To estimate mineral resources and reserves when core recovery was between 75% and 100%, the assayed value was deemed to be representative of the whole interval. If the core recovery was below 75%, the sample was replaced by length weighted probing values. Of the 3,271 assayed samples for Phase 1 mineralization, only 159 samples had recoveries of less than 75%.

• Sample composites were calculated at 1.0 metre intervals by taking the length weighted average for the mineralized intercept in each drillhole using a 1.0 % U₃O₈ cut-off grade.

Width	Assay	Density
•  largest 13.5 metres •  smallest 0.4 metres •  average 5.4 metres	•  highest 82.9% U3O8 •  lowest 0.0% U3O8	•  highest 8.44 g/cm3 •  lowest 1.27 g/cm3

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Quality control and data verification

The quality assurance and quality control procedures 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.

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 have reviewed a total of 1,286 original signed assay certificates, representing 29% of the 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 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

Please see page 73 for our mineral reserve and resource estimates for Cigar Lake.

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Uranium – projects under evaluation

Kintyre

Kintyre, which we acquired with a partner in 2008 diversifies our geographic reach and deposit types. We are the operator.

Location	Western Australia
Ownership	70%
End product	uranium concentrates
Mine type	open pit
Estimated mineral resources	38.7 million pounds (indicated) average grade U3O8 – 0.58%
(our share)	6.7 million pounds (inferred) average grade U3O8 – 0.46%

Business structure

Kintyre is owned by two companies:

• Cameco – 70%

• Mitsubishi Development Pty Ltd. – 30%

History

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

See our 2011 MD&A for more information.

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Uranium – projects under evaluation

Millennium

Millennium is a uranium deposit in northern Saskatchewan that we expect will use our excess milling capacity. We are the operator.

Location	Saskatchewan, Canada
Ownership	42%
End product	uranium concentrates
Mine type	underground
Estimated mineral resources	21.4 million pounds (indicated)
(our share)	average grade U3O8 – 4.55% 7.0 million pounds (inferred)
	average grade U3O8 – 2.54%

Business structure

Millenium is owned by a joint venture of three companies:

• Cameco – 42% (operator)

• AREVA – 28%

• JCU Exploration (Canada) Co. Ltd. – 30%

History

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

See our 2011 MD&A for more information.

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Exploration

Exploration is key to ensuring our long-term growth and since 2007 we have more than doubled our annual investment.

We carry out exploration mainly in Canada, the US, Australia, Mongolia, Kazakhstan and South America, on a total of approximately 5 million hectares (12.5 million acres) at December 31, 2011.

Our exploration activities include brownfield exploration near our existing operations, on our projects under evaluation, on advanced exploration projects where uranium mineralization is being defined, regional exploration in new target areas, and alliances or other agreements with junior exploration companies that own potential uranium targets.

Brownfield exploration

In 2011, we spent $10 million on five brownfield exploration projects, and $38 million for resource definition at Kintyre and at Cigar Lake.

Regional exploration

In 2011, we spent about $48 million on regional exploration programs (including support costs). Saskatchewan was the largest region, followed by Australia, northern Canada, Asia, and South America.

Plans for 2012

We plan to spend approximately $115 million on uranium exploration in 2012 as part of our long-term strategy.

Brownfield exploration

We plan to spend approximately $15 million on five brownfield exploration projects in the Athabasca Basin and Australia. Our expenditures on projects under evaluation are expected to total $35 million, with the largest amounts spent on Kintyre and Inkai block 3.

Regional exploration

We plan to spend about $65 million on 49 projects worldwide, the majority of which are at drill target stage. Among the larger expenditures planned are $9 million on two adjacent projects in Nunavut, $9 million to test targets near our US operations and on our satellite properties, $4 million on the Read Lake project, $5 million on targets in South Australia, and $5 million to follow up encouraging results on the Wellington Range project in Australia.

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Fuel services – refining

Blind River refinery

Blind River is the world’s largest commercial uranium refinery, refining uranium concentrates from mines around the world into UO₃.

Location	Ontario, Canada
Ownership	100%
End product	UO3
ISO certification	ISO 14001 certified
Licensed capacity	approved: 18 million kgU as UO3 per year
	application: 24 million kgU as UO3 per year
2011 production	13.5 million kgU of UO3
Estimated decommissioning cost	$38.6 million (pending regulatory approval)

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 13.5 million kgU of UO₃ this year. This ensured that SFL maintained its contractual inventories and Port Hope met is production requirements.

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 2011, we started the process to extend Blind River’s five-year licence to a 10-year licence, and expect the process to be completed in 2012. As part of the process, we anticipate that the regulator will consider an amendment to the licence to increase production. Once we receive approval, we will be in a position to make plant modifications to increase annual capacity to 24 million kgU per year.

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Fuel services – conversion and fuel manufacturing

We control about 25% of world UF₆ conversion capacity.

Port Hope conversion services

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

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	$101.7 million (pending regulatory approval)

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	$19.5 million (pending regulatory approval)

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 14.7 million kilograms of uranium in 2011.

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 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.

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Shutdowns

In July 2007, we discovered soil and groundwater contamination under the Port Hope UF₆ plant. We suspended production of UF₆ and conducted an investigation. We restarted the UF₆ plant in late September 2008, after significantly upgrading the liquid management structures and equipment.

In November 2008, we suspended UF₆ production a second time because we were not able to resolve a contract dispute and obtain anhydrous hydrofluoric acid (AHF) from our sole supplier on acceptable terms, and could not quickly source alternative supplies. AHF is a primary feed material for the production of UF₆. We signed an agreement with our original AHF supplier, and with two additional suppliers, and restarted production of UF₆ in June 2009.

In 2011, the UF₆ plant was shut down for a maintenance period of six weeks and the UO₂ plant was shut down for a maintenance period of five weeks.

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.

Port Hope conversion facility cleanup and modernization (Vision 2010)

The federal Minister of Environment approved the environmental assessment guidelines in 2009 for Vision 2010, 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 2011, work on the environmental assessment continued and public comments were provided to the CNSC. We have completed the disposition of all the comments received, and are waiting to receive approval from the Minister of Environment, which we expect will be in 2012. We will apply for an amendment to Port Hope’s licence once the assessment has been approved. We expect to submit the application in late 2012 or early 2013. The preliminary engineering and project design is complete, and now we are working on basic engineering.

We have agreed to buy two parcels of land for a better site layout after Vision 2010 is complete.

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 unfavourable market conditions for UF₆ conversion, we have discontinued discussions to extend our toll conversion contract with SFL beyond 2016. We are fully committed to the current contract. If market conditions improve over the next few years, we would consider resuming our discussions to extend the contract.

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.

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.

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Electricity

Bruce Power Limited Partnership (BPLP)

BPLP leases and operates four Candu nuclear reactors that have the capacity to provide about 18% of Ontario’s electricity.

Location	Ontario, Canada
Ownership	31.6%
ISO certification	ISO 14001 certified
Expected reactor life	2018 to 2021
Term of lease	2018 – right to extend for up to 25 years
Generation capacity	3,260 MW

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.
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.

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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 are scheduled to start again in 2012.

Average capacity factor

87% in 2011, and 91% in 2010. We expect it to be 95% 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

$243 million in 2011. We expect capital expenditures to be $258 million in 2012 (100% basis).

Employees

4,000 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.

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.

Unit power ratings

Before BPLP leased the Bruce reactors, studies revealed that emergency shutdown systems might not have sufficient safety margins for certain low probability events. As a result, the CNSC began limiting the four Bruce B units to operating at 90% of maximum power.

BPLP has had some success in addressing this issue, by reordering the fuel core for example, which has improved safety margins. In 2004, the CNSC approved the uprating of the Bruce B5, 6 and 7 units to up to 93% of maximum power. The Bruce B8 unit received this rating in March 2010.

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BPLP is looking at other ways to address this issue, including modifying the reactor shutdown systems and making minor modifications to the existing fuel design.

BPLP believes the technical steps it is taking are sufficient to address the issue, but future derating is possible, including small deratings to maintain operating safety margins as the units age.

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 will operate until:

• 2021 for the Bruce B8 unit

• 2018 to 2019 for the other three B units.

BPLP is looking at whether it can demonstrate that longer operating life is possible for the units. It has also been assessing the condition and life expectancy of several of their key components, including steam generators, fuel channels and feeder pipes.

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. BPLP believes that all of the inner tubes in the steam generators are likely to degrade, and that regular cleaning, repairs and internal modifications are necessary to slow down the rates of degradation and restore reliability of the units. BPLP continues to carry out a maintenance plan with the goal of keeping the steam generators operating for the expected life of the units. Current estimates of steam generator life are within the estimated operating lives of the units.

In 2003, inspections of the Bruce B8 unit identified some erosion on the support plates in three of the eight steam generators. BPLP repaired the damage and did not find any issues with the boiler tubes. It inspected the other units and did not find any similar issues, and follow-up inspections of the B8 unit did not show any further significant degradation. An inspection in 2009 confirmed that the mitigating actions appear to have been effective at stopping the erosion on these support plates.

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 implementation in 2013.

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 inspects for pipe cracking during planned outages, but has not found any cracking to date. It increased the scale of these inspections, however, in response to the cracking of feeder pipes at two Candu plants outside Ontario, where the cracked sections were replaced and the units returned to service.

BPLP does not expect the feeder pipes to limit the life of the Bruce B units, although they do expect to have to replace some feeder pipes, and to replace and upgrade pipes for safe operation during the operating lives of the units.

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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 for financial assurances given on behalf of BPLP was an estimated $77 million at December 31, 2011.

These include guarantees in favour of OPG under the lease (as discussed below) and guarantees to support BPLP’s power purchase agreements with customers. This last commitment is adjusted as wholesale electricity market prices change. As at December 31, 2011, our actual exposure was $11 million. See note 31 to the 2011 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 90 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 which is now being reviewed by the Ontario Financing Authority (OFA). The updated estimate decreased compared to the review completed in 2006 and therefore no adjustments to the base rent are anticipated. The OFA review should be completed in 2012.

In addition to base rent, BPLP pays an annual supplemental rent ($30 million) for each Bruce B operating reactor that increases with inflation. If the annual average price of electricity falls below $30 per megawatt hour, the supplemental rent decreases to $12 million per operating reactor.

In 2011, the total lease payments were $168 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

2011 ANNUAL INFORMATION FORM Page 71

• meets specified shut-down conditions before handover.

We have guaranteed BPLP’s performance of these obligations to a maximum amount of $58.3 million.

Reinforcing the system

The transmission system from the Bruce Power site will need to be reinforced once all eight units are back in service and the expected wind powered facilities in the Bruce area are operational. This involves adding a new 500 kilovolt line between Bruce Power and Milton, essentially doubling the current transmission capacity. Hydro One is planning for the transmission reinforcement to be in service in 2012.

2011 ANNUAL INFORMATION FORM Page 72

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 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 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.

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 $58 (US) per pound U₃O₈ (unless otherwise noted), 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.

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. Metallurgical recovery is an estimate of the amount of valuable product that can be physically recovered by the metallurgical extraction process, and is calculated by multiplying the quantity of contained metal by the estimated metallurgical recovery percentage. Our share of uranium in the mineral reserves table below is before accounting for estimated metallurgical recovery.

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 prepared by, or under the supervision of, individuals who are qualified persons for the purposes of NI 43-101:

2011 ANNUAL INFORMATION FORM Page 73

McArthur River/Key Lake		Cigar Lake
•	Alain G. Mainville, director, mineral resources management, Cameco	•	Alain G. Mainville, director, mineral resources management, Cameco
•	David Bronkhorst, vice-president, Saskatchewan mining south, Cameco	•	Scott Bishop, principal mine engineer, technology & innovation, Cameco
•	Greg Murdock, technical superintendent, McArthur River, Cameco	•	Grant Goddard, vice-president, Saskatchewan mining north, Cameco
•	Les Yesnik, general manager, Key Lake, Cameco	•	Eric Paulsen, interim chief metallurgist, technology & innovation, Cameco
Inkai
•	Alain G. Mainville, director, mineral resources management, Cameco
•	Dave Neuburger, vice-president, international mining, Cameco
•	Lawrence Reimann, manager, technical services, Cameco Resources

Important information about mineral reserve and resource estimates

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

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

• geological interpretation

• extraction plans

• commodity prices and currency exchange rates

• recovery rates

• operating and capital costs.

There is no assurance that the indicated levels of uranium will be produced, and we may have to re-estimate our mineral reserves based on actual production experience. Changes in the price of uranium, production costs or recovery rates could make it unprofitable for us to operate or develop a particular site or sites for a period of time. See page 1 for information about forward-looking information, and page 99 for a discussion of the risks that can affect our business.

Please see page 79 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.

2011 ANNUAL INFORMATION FORM Page 74

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.

Mineral reserves

As at December 31, 2011 (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)		Estimated metallurgical recovery (%)
McArthur River	underground		457.5		22.07		222.6		412.7		11.14		101.4		870.2		16.89		324.0		226.2		98.7
Cigar Lake	underground		233.6		22.31		114.9		303.5		15.22		101.8		537.1		18.30		216.7		108.4		98.5
Rabbit Lake	underground		91.0		0.52		1.0		1,399.9		0.75		23.0		1,490.9		0.73		24.0		24.0		96.7
Key Lake	open pit		61.9		0.52		0.7								61.9		0.52		0.7		0.6		98.7
Inkai	ISR		3,772.4		0.08		6.9		63,692.4		0.07		92.6		67,464.8		0.07		99.5		59.7		85.0
Gas Hills-Peach	ISR								999.2		0.11		2.4		999.2		0.11		2.4		2.4		72.0
North Butte-Brown Ranch	ISR								1,839.3		0.09		3.7		1,839.3		0.09		3.7		3.7		80.0
Smith Ranch-Highland	ISR		1,124.7		0.11		2.7		2,263.4		0.08		3.9		3,388.1		0.09		6.6		6.6		80.0
Crow Butte	ISR		1,282.6		0.13		3.7								1,282.6		0.13		3.7		3.7		85.0
Total			7,023.7		—		352.5		70,910.4		—		328.8		77,934.1		—		681.3		435.3

Notes

ISR - in situ recovery

Estimates in the above table:

• use an average uranium price of $58.00 (US)/lb U₃O₈ , except for Cigar Lake which uses an average uranium price of $61.00 (US)/lb U₃O₈

• are based on an average exchange rate of $1.00 US=$1.02 Cdn, except Cigar Lake, which is based on an average exchange rate of $1.00 US=$1.10 Cdn

Totals may not add up due to rounding.

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

Metallurgical recovery

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

2011 ANNUAL INFORMATION FORM Page 75

Estimates for Inkai

Our 2012 and future annual production targets and mineral reserve estimate for Inkai assume and we expect:

• Inkai will obtain the necessary government permits and approvals to produce at an annual rate of 5.2 million pounds (100% basis), including an amendment to the resource use contract

• we reach a binding agreement with Kazatomprom to finalize the terms of the memorandum of agreement

• Inkai will ramp up production to an annual rate of 5.2 million pounds (100% basis).

There is no certainty Inkai will receive these permits or approvals or we will reach a binding agreement with Kazatomprom or that Inkai will be able to ramp up production. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2012 and future annual production targets and we may have to recategorize some of Inkai’s mineral reserves as resources.

Changes this year

The table below shows the change in our share of mineral reserves for each property in 2011. The change was mostly the result of:

• mining and milling activities, which used 23.4 million pounds

• conversion of probable mineral reserves to proven mineral reserves from additional drilling results and/or refinements to the mining and freezing plans at McArthur River and Cigar Lake

• conversion of mineral reserves to mineral resources for portions of Gas Hills-Peach and North Butte-Brown Ranch where it was recognized that the project risks and economic assessments could be improved by modeling individual roll-fronts instead of combining them as one mineralized unit

• a requirement at Inkai to produce equal amounts from blocks 1 and 2 which resulted in an update of the life of mine production schedule and conversion of pounds from mineral reserves to mineral resources.

(thousands of pounds U3O8)	December 31, 2010		Throughput			Additions (deletions)			December 31, 2011
Proven mineral reserves
Cigar Lake		36,861					20,612			57,473
Crow Butte		2,297		(905	)		2,294			3,686
Inkai		5,322		(1,233	)		79			4,168
Key Lake		590								590
McArthur River		122,003		(13,922	)		47,325			155,406
Rabbit Lake		545		(246	)		740			1,039
Smith Ranch-Highland		3,122		(1,780	)		1,347			2,689
		170,740		(18,086	)		72,397			225,051
Probable mineral reserves
Cigar Lake		67,819					(16,869	)		50,950
Crow Butte		784					(784	)		0
Gas Hills - Peach		18,984					(16,553	)		2,431
Inkai		67,625		(1,708	)		(10,383	)		55,534
McArthur River		112,177					(41,396	)		70,781
North Butte – Brown Ranch		8,208					(4,488	)		3,720
Rabbit Lake		25,008		(3,575	)		1,601			23,034
Smith Ranch-Highland		4,904					(985	)		3,919
		305,509		(5,283	)		(89,857	)		210,369
Total mineral reserves		476,249		(23,369	)		(17,460	)		435,420

Notes

Throughput corresponds to millfeed. The difference between 2011 millfeed and Cameco’s share of 2011 pounds U₃O₈ produced is from mill recovery, mill inventory and processing low-grade material.

Additions (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.

2011 ANNUAL INFORMATION FORM Page 76

Mineral resources

As at December 31, 2011 (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)
McArthur River	underground		73.7		5.58		9.1		114.4		25.40		64.0		188.1		17.63		73.1		51.0
Cigar Lake	underground		18.9		1.68		0.7		25.5		2.71		1.5		44.4		2.25		2.2		1.1
Kintyre	open pit								4,315.4		0.58		55.2		4,315.4		0.58		55.2		38.7
Rabbit Lake	underground								362.4		0.53		4.3		362.4		0.53		4.3		4.3
Dawn Lake	open pit, underground								347.0		1.69		12.9		347.0		1.69		12.9		7.4
Millennium	underground								507.8		4.55		50.9		507.8		4.55		50.9		21.4
Phoenix	underground								89.9		17.98		35.6		89.9		17.98		35.6		10.7
Tamarack	underground								183.8		4.42		17.9		183.8		4.42		17.9		10.3
Inkai	ISR								28,613.1		0.08		48.0		28,613.1		0.08		48.0		28.8
Gas Hills-Peach	ISR		1,964.2		0.08		3.4		7,821.9		0.11		18.8		9,786.1		0.10		22.2		22.2
North Butte-Brown Ranch	ISR								7,248.9		0.08		12.3		7,248.9		0.08		12.3		12.3
Smith Ranch-Highland	ISR		2,158.3		0.11		5.1		14,778.0		0.06		18.6		16,936.3		0.06		23.7		23.7
Crow Butte	ISR								2,592.2		0.21		11.9		2,592.2		0.21		11.9		11.9
Ruby Ranch	ISR								2,215.3		0.08		4.1		2,215.3		0.08		4.1		4.1
Ruth	ISR								1,080.5		0.09		2.1		1,080.5		0.09		2.1		2.1
Shirley Basin	ISR		89.2		0.16		0.3		1,638.2		0.11		4.1		1,727.4		0.12		4.4		4.4
Total			4,304.3		—		18.6		71,934.3		—		362.2		76,238.6		—		380.8		254.4

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.
McArthur River	underground		405.2		9.67		86.4		60.3
Cigar Lake	underground		448.0		12.59		124.4		62.2
Kintyre	open pit		950.2		0.46		9.6		6.7
Rabbit Lake	underground		331.9		1.42		10.4		10.4
Millennium	underground		297.8		2.54		16.7		7.0
Phoenix	underground		23.8		7.27		3.8		1.1
Tamarack	underground		45.6		1.02		1.0		0.6
Inkai	ISR		254,696.0		0.05		255.1		153.0
Gas Hills-Peach	ISR		861.5		0.07		1.3		1.3
North Butte-Brown Ranch	ISR		594.3		0.06		0.8		0.8
Smith Ranch-Highland	ISR		6,404.0		0.05		6.6		6.6
Crow Butte	ISR		2,282.2		0.12		6.0		6.0
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			268,115.6		—		523.8		317.7

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Changes this year

The table below shows the change in our share of mineral resources for each property in 2011. The change was mostly the result of:

• first time reporting of mineral resources at Kintyre

• conversion of inferred mineral resources to indicated mineral resources at McArthur River

• conversion of mineral reserves to mineral resources at Gas-Hills Peach and Inkai

• a requirement at Inkai to produce equal amounts from blocks 1 and 2 which resulted in an update of the life of mine production schedule and transfer of pounds from mineral reserves to mineral resources

• additional drilling at Cigar Lake.

(thousands of pounds U3O8)	December 31, 2010		Additions (deletions)			December 31, 2011
Measured mineral resources
Cigar Lake		193		158			351
Gas Hills – Peach		3,372					3,372
McArthur River		8,308		(1,974	)		6,334
North Butte – Brown Ranch		1,366		(1,366	)		0
Shirley Basin		304					304
Smith Ranch-Highland		4,928		157			5,085
		18,471		(3,025	)		15,446
Indicated mineral resources
Cigar Lake		405		356			761
Crow Butte		11,175		678			11,853
Dawn Lake		7,436					7,436
Gas Hills – Peach		2,268		16,553			18,821
Inkai		18,271		10,530			28,801
Kintyre				38,657			38,657
McArthur River		3,488		41,221			44,709
Millennium		21,369					21,369
North Butte – Brown Ranch		5,984		6,357			12,341
Phoenix		10,691					10,691
Rabbit Lake		4,002		254			4,256
Ruby Ranch		4,078					4,078
Ruth		2,097					2,097
Shirley Basin		4,085					4,085
Smith Ranch-Highland		17,647		925			18,572
Tamarack		10,288					10,288
		123,284		115,531			238,815
Total measured and indicated mineral resources		141,755		112,506			254,261

2011 ANNUAL INFORMATION FORM Page 78

(thousands of pounds U3O8)	December 31, 2010		Additions (deletions)			December 31, 2011
Inferred mineral resources
Cigar Lake		66,792		(4,585	)		62,207
Crow Butte		5,593		371			5,964
Gas Hills – Peach		1,289					1,289
Inkai		153,049					153,049
Kintyre				6,719			6,719
McArthur River		104,835		(44,509	)		60,326
Millennium		4,271		2,736			7,007
North Butte – Brown Ranch		900		(73	)		827
Phoenix		1,143					1,143
Rabbit Lake		10,244		171			10,415
Ruby Ranch		167					167
Ruth		365					365
Shirley Basin		1,132					1,132
Smith Ranch-Highland		6,560		15			6,575
Tamarack		591					591
Total inferred mineral resources		356,931		(39,155	)		317,776

Note

Additions (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

Key assumptions

• Mineral reserves include allowances for dilution (20%) and mining recovery (95%). Mineral resources do not include allowances for either.

• Mineral resources are estimated at a minimum mineralized thickness of 1.0 metre and at a cutoff grade of 0.1% to 0.5% U₃O₈. Mineral reserves are estimated at a cut-off grade of 0.8% U₃O₈ .

Key parameters

• For mineral resources estimated from surface drillholes, the uranium grade is determined from assay sample.

• For mineral resources and mineral reserves estimated from underground drillholes, grades are determined by converting radiometric probing to percentage 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 using the raisebore, boxhole and blasthole stoping methods combined with freeze curtains. The planned mining rate is to vary between 150 and 200 tonnes per day at a full mill production rate of 18.7 million pounds U₃O₈ per year based on 98.7% mill recovery.

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Key methods

• Mineral resources were estimated using 3-dimensional block models. The models were created from the geological interpretation of mineralization outlines using lithology, structure and uranium grade information interpreted on vertical cross-sections and plan views. Estimates of block grade and density were obtained with ordinary kriging or inverse squared distance methods.

Cigar Lake

Key assumptions

• Phase 1 mineral resources (the eastern part of the deposit, 700 metres long by 150 metres wide) have been estimated within minimum mineralization thickness of 1.0 metres and a cut-off grade of 1% U₃O₈. The Phase 2 mineral resources (the western part of the deposit, 1,200 metres long by 100 metres wide) have been estimated with a minimum mineralization thickness of 2.5 metres, including 1.0 metres of dilution and a cut-off grade of 5.9% U₃O₈ .

• Phase 1 mineral resources have been estimated with no allowance for mining dilution or mining recovery. No mining recovery was applied to Phase 2 mineral resources.

• Mineral reserves have been estimated at a cut-off grade of 2.0% U₃O₈ and a minimum mineral thickness of 1.5 metres, after measuring the diluted grade.

• Mineral reserves have been estimated with an allowance of 0.5 metres of dilution material above and below the ore zone, plus 11% external dilution at 0% U₃O₈. Mineral reserves have been estimated based on 90% mining recovery.

Key parameters

• Grades of U₃O₈ were obtained from chemical assaying of drill core and checked against radiometric probing results. In areas of lost core 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. Phase 1 mineral resources and mineral reserves were estimated using a 3-dimensional block model. Phase 2 mineral resources were estimated using a 2-dimensional block model. Ordinary kriging was used to estimate the grade and density of the blocks.

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 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.

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• 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 believe that Kazakhstan’s reserves categories B, C1 and C2 correspond respectively 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 .

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 core drillhole information.

• Mineral resources and mineral reserves were estimated with the grade-thickness method using 2-dimensional block models.

2011 ANNUAL INFORMATION FORM Page 81

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. We work under strict government regulation at every stage – from exploration and development, to decommissioning and reclamation.

Rather than viewing sustainable development as an “add-on” to traditional business activity, however, we see it as an integral component to the way we do business. Our aim is to fully integrate sustainable development principles and practices at each level of our operations. We are committed to complying with and moving beyond legal and other requirements, and we operate in a manner that is consistent with the ALARA principle: protecting the environment by limiting emissions and managing waste so levels are as low as reasonably achievable, accounting for social and economic factors.

We measure our progress using 23 key performance indicators that reinforce our corporate strategy and align with our four measures of success:

Safe and rewarding workplace

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

Clean environment

We are committed to operating our business with respect and care for the local and global environment. We strive to be a leader in environmental practices and performance by complying with legal and other requirements, and moving beyond them where possible.

We are committed to integrating environmental leadership into everything we do. Part of the way we determine our progress is by measuring our impact on air, water and land near our operations as well as generation of waste and emissions.

Supportive communities

We work to build and sustain the trust of local communities by acting as a good corporate citizen. We measure the amount invested in communities through sponsorships and donations, community support through annual polling and regional employment figures.

Outstanding financial performance

To fulfill our vision, we must be competitive and secure the support of our stakeholders. We measure our financial performance based on our ability to achieve a number of strategic objectives, which are set and reviewed annually.

Our 2011 and 2012 objectives are based on, and our performance is measured against, these four measures of success. See our 2011 MD&A for our 2011 objectives, our performance against those objectives and our 2012 objectives.

Focus on environmental leadership

Our business by its nature has an impact on the environment, so environmental leadership is a key area of focus for us and a strategic priority for our operations.

Environmental leadership 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 over a three-year period. You can find this information on our website (cameco.com) and in our sustainable development report, which is also available on our website.

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SHEQ management system

We introduced our environmental, safety and health policies in 1991, and have refined our approach over the years to form our overall integrated management system: the SHEQ management system.

The system includes our statement of environmental principles, and seven programs for implementing the policies and fulfilling our commitments in these areas.

Our environmental principles

• keep risks at levels as low as reasonably achievable, accounting for social and economic factors

• prevent pollution

• comply with and move beyond legal compliance requirements

• ensure quality of processes, products and services

• continually improve our overall performance.

Seven SHEQ programs

• Quality management program

• Safety and health management program

• Radiation protection program

• Environment management program

• Management system audit program

• Emergency preparedness and response program

• Contractor management program

We benchmark our system against those used by other companies in the mining and nuclear power generation sectors. The board’s safety, health and environment committee oversees our environmental policies and programs and our environmental performance on behalf of the board. Our chief executive officer is responsible for ensuring the system is implemented across the company.

Our SHEQ management system is centralized and managed at the corporate level, and we implement it corporately and at our operations.

The corporate 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.

The SHEQ audit function is integrated with our other internal audit functions. 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 consistently applying policies and procedures, and providing help with technical issues. The sites carry out 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 2011, we invested:

• $99 million in environmental protection, monitoring and assessment programs, or 30% more than 2010

• $30 million in health and safety programs, or 12% less than 2010.

Spending for health and safety programs in 2012 is expected to be similar to 2011, while spending for environmental programs is expected to increase slightly.

We had 31 reportable environmental events in 2011, compared to 22 in 2010, however, there were no significant environmental incidents in 2010 and 2011.

In 2011, we achieved strong safety performance at our operations.

You can find more information about our SHEQ management system on our website.

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Reducing our impact

Our internal team of specialists has been carrying out our long-term plan to reduce the impact we have on the environment. This includes monitoring and reducing our effect on air, water and land, reducing the greenhouse gases we produce and 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 this continues to improve our safety and environmental performance and operating efficiency.

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 29 years) and Rabbit Lake mill (in operation for 37 years).

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.

Land

Our 10 operating sites affect approximately 30 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. and Kazakhstan 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 are reducing the concentrations of molybdenum and selenium in the effluent released from our northern Saskatchewan mines and mills because the continued release of these substances at higher levels may impact the environment.

Key Lake

The CNSC accepted our action plan in 2007 to reduce molybdenum and selenium discharges in Key Lake mill effluent, and made it a condition of the facility’s operating licence. We have since reduced the concentrations of both substances in the effluent and the treatment circuit continues to perform well with consistent control of effluent concentrations.

McArthur River

We are reducing the amount of molybdenum McArthur River discharges into the environment:

• The three shafts at the site seep good quality water. We are capturing it and using it for underground mining, rather than piping more water down from the surface.

• The water quality from shaft 3 has been assessed and approved for discharge to the environment without treatment, so we discharge all excess water picked up in shaft 3 directly to the environment. This keeps the water away from underground processes, reducing the concentration of molybdenum.

• We are studying how to send excess water from the other shafts directly to the surface water treatment plant.

We expect these activities to reduce both the volume of effluent treated and the concentration of molybdenum in the effluent. As part of the most recent CNSC re-licensing, we committed to a target for lowering molybdenum and have been using a staged approach to optimize the treatment. We have implemented a number of specific activities that

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have led to significantly lower concentrations and loadings and results that are consistently below this target.

Rabbit Lake

We modified the Rabbit Lake mill in 2009 and reduced discharges of molybdenum and selenium.

We installed a water treatment circuit in 2006 to reduce uranium in the discharge and, as of 2007, there is an average of 10 times less uranium being discharged than there was before 2004 calculated on an annual basis.

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

We discovered soil and groundwater contamination under the Port Hope UF₆ conversion plant in July 2007, and suspended operation to investigate. See Shutdowns on page 67 for information about the environmental effect of the incident, how we responded and the steps we took to resume operation of the plant.

We also shut down the UO₂ plant for an extended planned maintenance period in 2008, and brought floors and in-floor structures up to the new standards of the UF₆ plant. We discovered a leaking sump, which appeared to be the source of some localized contaminated ground water we found in an earlier assessment. We installed a new groundwater collection well next to the UO₂ plant to control contaminated groundwater, and reopened the plant in mid-January 2009.

Improvements to the UF₆ and UO₂ plants cost $50 million. We also spent $14 million to remediate the contaminated soil and groundwater from the Port Hope UF₆ plant.

All fuel services sites have environmental management systems that are ISO14001 registered, and CFM received its registration in 2011. Continuous improvement is a key aspect of the management systems, and both our Port Hope Conversion Facility and Blind River Refinery have successfully reduced emissions.

In our efforts to reduce the potential risks of our operations, Blind River has successfully eliminated the use of anhydrous ammonia in the refining process while still meeting the current production requirements.

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.

We have 10 wellfields under restoration. See page 91 for more information.

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.

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	2011		2010		2009
Greenhouse gas emissions of tonnes of CO2 equivalent (CO2e)		502,342		464,718		460,054
Greenhouse gas emissions include carbon dioxide, methane, nitrous oxide, sulphur hexafluoride, hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs) expressed as a carbon equivalent (CO2e).

The greenhouse gas emissions have been slowly increasing since 2005. Expansion of our operations has caused increases in fuel consumption, and therefore emissions, as expected.

Port Hope

We have lowered emissions of uranium and hydrofluoric acid to the air by installing new equipment and changing the operating procedures.

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, we installed a new acid plant at Key Lake that will substantially decrease SO₂ emissions.

Rabbit Lake

Substantial upgrades to the acid plant at Rabbit Lake have resulted in an approximate 70% 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).

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 all runoff and treat any seepage 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 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. We must complete an

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environmental assessment before we begin developing a new mine or start processing activities, or make any significant change to a plan that has already been approved. Once we have permanently stopped mining and processing activities, we are required to decommission and reclaim the operating site to the satisfaction of the regulator, 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 Canadian 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.

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.

Generally, the environmental assessment process takes 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, including comprehensive studies and screening level assessments. 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.

Many of these initiatives have required additional environmental studies near the operations, and we expect that we will have to do more, including environmental assessments.

It can take a significant amount of time for regulators to make requested changes to a licence or grant requested approval because the proposal 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 more often 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.

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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 2012 production plans.

Our plans to expand our US ISR production, which includes adding satellite facilities to our operating mines in Wyoming and Nebraska, are subject to an environmental assessment process that can take several years.

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 page 91 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.

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 2013, and an emissions permit for drilling activities, valid until December 2012. 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.

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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 the regulator 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 2011, our estimate of total decommissioning and reclamation costs was $577 million. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $509 million at the end of 2011 (the present value of the $577 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 $664 million in letters of credit supporting our reclamation liabilities at the end of 2011. Since 2001, all of our North American operations have had letters of credit in place that provide financial assurance in connection with our preliminary plans for decommissioning for the sites.

Please also see note 19 to the 2011 financial statements for our estimate of decommissioning and reclamation costs and related letters of credit.

Canada

Decommissioning estimates (100% basis)
McArthur River	$	36.1 million
Rabbit Lake	$	105.2 million
Key Lake	$	120.7 million
Cigar Lake	$	27.7 million

These estimates have been reviewed and accepted by the CNSC. We, along with our joint venture partners, have filed with the Saskatchewan government letters of credit as financial assurance for all four operations to match these estimates.

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.

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Decommissioning estimates (100% basis)
Port Hope	$	101.7 million
Blind River	$	38.6 million
CFM	$	19.5 million

We are currently in the process of renewing our licences for Port Hope, Blind River and CFM and are awaiting regulatory approval of our new decommissioning estimates for these sites. Once the new decommissioning estimates are approved, we will increase the letters of credit to be filed with the regulator as financial assurance for them.

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.

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 and the Welcome Waste Management Facility in Port Hope.

Our liability includes:

• the first $2 million of all costs and expenses related to historical waste and the historical facilities, including costs and expenses relating to any claim arising out of or related to historical waste and decommissioning or reclamation costs and expenses related to historical waste and the historical facilities

• 23/98ths of the next $98 million of these costs.

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Canada Eldor Inc., the entity established by the federal government to assume the historical liabilities and obligations of Eldorado Nuclear Limited, retained liability for the balance of these costs up to $100 million, and for all of these costs above $100 million, effectively capping our liability with respect to these costs at $25 million.

Principles of understanding

In October 2000, the government of Canada and certain communities near and including Port Hope announced they had signed a framework for the development of an agreement for the clean-up, storage and long-term management of certain historical waste (the principles of understanding).

In June 2001, the federal government announced that it had signed an agreement to invest approximately $260 million over 10 years to carry out the work.

In March 2004, we reached an agreement to transfer two facilities to the government of Canada: the Port Granby Waste Management Facility and Welcome Waste Management Facility. Atomic Energy Canada Limited (AECL), which indirectly owned these waste sites before 1988 through its ownership of Eldorado Nuclear Limited, is the licensee.

As part of this transaction, the federal government agreed to accept approximately 150,000 cubic metres of low-level radioactive waste from us at no charge. It also agreed to assume all liability for the waste at the two sites, as long as we met our obligation to contribute the balance of the $25 million cap respecting costs and expenses related to historical waste and the historical facilities remaining upon the transfer of the final waste facility. We have already recognized this $25 million liability, but at the end of 2011, only $7.17 million of it had been spent by Cameco.

Port Hope Area Initiative

In July 2002, the federal government released the scoping document for the environmental assessment of the Port Hope Area Initiative, which described two projects to manage low-level radioactive waste in the Port Hope area for the long term: the Port Granby project and Port Hope project, which includes historical waste at the Welcome Waste Management Facility. Both projects have completed the environmental assessment process.

In September 2009, after a one-day public hearing, the CNSC announced a decision to issue a Waste Nuclear Substance Licence to AECL for the Welcome Waste Management Facility, valid as of the date of land transfer. Transfer of this facility to the federal government was completed on March 31, 2010. In November 2011, the CNSC announced the decision to issue a Waste Nuclear Substance Licence to AECL for the Port Granby Waste Management Facility, valid as of the date of the land transfer, which is anticipated to occur in 2012.

Recycling uranium byproducts

We have an agreement with Denison Mines Corporation 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.

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.

It is difficult for us to estimate final timing for restoring wellfields due to the uncertainty in timing for receiving 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.

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Our estimated cost of decommissioning the property is $35.6 million (US). We have provided the State of Nebraska with a $35.4 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 $35.6 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.

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. We have restored the groundwater at mine unit A to pre-mining quality standards, and continue to monitor the area’s environmental performance. We have received regulatory approval for the restoration at mine unit A.

Our estimated cost of decommissioning the property is $168 million (US). We have provided the State of Wyoming with $212.7 million (US) in letters of credit as security for decommissioning the property, 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 $11 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 85 for additional details.

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The regulatory environment

This section, and the section Complying with environmental regulations starting on page 86, 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 five main regulatory agencies that issue licences and approvals:

• CNSC (federal)

• Fisheries and Oceans Canada (federal)

• Transport 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.

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

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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 has more recently stated in October 2011 that it will not be changing the policy at this time.

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 122 and 123 for more information.

Industry governance

The Canadian Nuclear Safety and Control Act (NSCA) governs the control of the mining, extraction, use and export of uranium in Canada. It is a federal statute, authorizing the CNSC to make regulations governing all aspects of the development and application of nuclear energy, including uranium mining, milling, conversion, fabrication and transportation. It grants the CNSC licensing authority for all nuclear activities in Canada. 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 provisions for dealing with the licence requirements of facilities, radiation protection, physical security for all nuclear facilities and the transport of radioactive materials. The CNSC has also issued regulatory information and guidance 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.

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. In some cases, such as with China, we also need government agreements and bilateral arrangements.

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

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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, 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 the Nuclear Liability Association of Canada. 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.

• 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.

The federal government had previously introduced legislation in the House of Commons that would significantly change the Nuclear Liability Act. It included, among other things, requirements for the operator to maintain $650 million of liability insurance for each of its nuclear stations. While not currently before the House of Commons, it is expected that this legislation will be reintroduced. If it becomes law, it will result in a significant increase in the cost and amount of insurance coverage BPLP must obtain.

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.

BPLP expects these actions to depress the wholesale contract market, which is unregulated.

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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.

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.

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.

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.

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 on page 41.

Royalties and taxes

Canadian royalties

We pay royalties to the province of Saskatchewan under the terms of Part III of the Crown Mineral Royalty Schedule, 1986 (Saskatchewan), as amended. The royalty applies to the sale of all uranium extracted from orebodies in the province.

The schedule includes two kinds of royalties:

• basic royalty: 5% of gross sales of uranium, less the Saskatchewan resource credit (1% of the gross sales of uranium)

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• tiered royalty: an additional percentage of gross sales of uranium, when the realized sales price of uranium (after deducting capital allowances) is higher than the sales prices listed in the schedule.

We claimed all of our capital allowances in 2007 and started to pay tiered royalties that year. We will be eligible for additional capital allowances once Cigar Lake begins production, resulting in significantly reduced tiered royalties that fiscal year and the year following at which time the allowances are expected to be fully exhausted.

As a resource corporation in Saskatchewan, we 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 recovery for 2011 was $7.9 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.

Since 2008, Canada Revenue Agency (CRA) has disputed the transfer pricing methodology we used for certain uranium sale and purchase agreements and issued notices of reassessment for our 2003 through 2006 tax returns. We believe it is likely that CRA will reassess our tax returns for 2007 through 2011 on a similar basis. Our view is that CRA is incorrect, and we are contesting its position. As a result, we are pursuing our appeal rights under the Income Tax Act. However, to reflect the uncertainties of CRA’s appeals process and litigation we have provided $54 million for uncertain tax positions for 2003 through 2011. We believe that the ultimate resolution of this matter will not be material to our financial position, results of operations or liquidity over the period. However, an unfavourable outcome for the years 2003 to 2011 could be material to our financial position, results of operations or cash flows in the year(s) of resolution. See note 24 to the financial statements.

US taxes

Our subsidiaries in Wyoming and Nebraska pay severance taxes, property taxes and Ad Valorem taxes in those states. They paid $5.6 million (US) in taxes in 2011.

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. Current income tax expense for 2011 was $0.1 million (US).

Kazakhstan taxes

The resource use contract lists the taxes, duties, fees, royalties and other governmental charges Inkai has to pay.

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. We do not expect the new tax code to have a material impact on Inkai at this time, but eliminating the tax stabilization provision could be material in the future. See pages 40 and 41 for more information about the resource use contract.

Corporate income tax rate

Under the new tax code, 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 new 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 is 22%.

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Previously, Inkai would pay royalties that were calculated on a graduated scale, based on the sales price of production each year.

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, that rate increases 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.

Please also see the risk discussion in our 2011 MD&A.

Types of risk
Operational	99
Political	107
Regulatory	109
Financial	110
Environmental	115
Legal and other	117
Industry	119

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, like 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 contracted or purchased materials, supplies and services

• 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

• equipment failures

• catastrophic accident

• fires

• blockades or other acts of social or political activism

• regulatory constraints ad non-compliance with laws and licences

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

• 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.

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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.

Not having the right insurance coverage or the right 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, but 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.

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 page 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

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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, ore-handling and transport and other mining-related challenges.

The jet boring mining method is new to the uranium mining industry and 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 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.

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.

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 gives us about six years of licensed capacity at current production rates, assuming we experience only minor losses in storage capacity because of sloughing from the pit walls. We also completed prefeasibility work in 2009, to assess our options for additional long-term tailings storage. Work is well underway on the environmental assessment 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 and resources from the McArthur River operation and 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 2016. We are planning for an expansion of the tailings management facility to be ready by mid-2016. This will support the extension of Rabbit Lake’s mine life and provide additional tailings capacity to process ore from other potential sources. We formally started the environmental assessment process in 2011 to receive regulatory approval for the expansion in tailings capacity.

If sloughing or other issues prevent us from maintaining the existing tailings management capacity at the Deilmann

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TMF and Rabbit Lake pit, or if we 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 is our major development project and we have several other projects under evaluation: expansion of production from Inkai blocks 1 and 2 and development of Inkai block 3 in Kazakhstan, McArthur River extension, expansion of production from our US ISR operations, development of Millennium in Saskatchewan, and development of Kintyre in Australia.

Several factors affect the economics and success of development projects:

• 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.

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 development 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 operations to experience unexpected problems during start-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.

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Developing additional reserves to sustain operations

The McArthur River, Rabbit Lake and Inkai mines are currently our main sources of mined uranium concentrates. We expect the reserves at our Rabbit Lake mine to be depleted in 2017.

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 Inkai block 3, Millennium and Kintyre deposits are not successfully developed

• production from our US ISR sites is not increased

• 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. We believe that Cigar Lake will achieve its planned levels of production, but 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 fueled 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.

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 negative impact on uranium prices and the share price of companies involved in uranium exploration and development.

Japan has 54 nuclear reactors. As of February 8, 2012, Japan had three reactors operating. These three reactors are scheduled to enter regular maintenance shutdowns between late February and the end of April, at which time we expect all of Japan’s nuclear reactors will be offline. Many are unaffected by the events in March 2011 but are offline for both planned and unplanned maintenance outages, and diminished public support has prevented utilities from gaining the regulatory and political approvals necessary to restart them. The Japanese government has ordered stress tests to be conducted on all reactors before allowing them to restart, and is implementing reforms to its existing nuclear regulatory framework and energy policy. Stress tests are progressing, but the government has not made any

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final decisions about restarting the reactors. Local governement approval will also likely be required to allow reactors to restart. Japan’s 54 reactors represent 12% of global nuclear generating capacity.

Germany, which represents 5% of world nuclear generating capacity, decided to revert to its previous phase-out 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.

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

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electrical heating, while variations in summer weather affect the demand for electrical cooling.

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. Ontario demand in 2011 was down by 0.5% or 0.7 TWh compared to 2010. While this decrease signals continued inertia in the economy, 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 will need additional financial, administrative, technical and operations staff to fill key positions as our business activity grows and we 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, 2011, we had 3,470 employees (including employees of our subsidiaries, but not including Inkai or BPLP). This includes 910 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 4,000 employees, and most of them are unionized.

Collective agreements

• The collective agreement with the bargaining unit employees at CFM expires on June 1, 2012. This agreement was signed following a three-month strike in 2009.

• The collective agreement with the bargaining unit employees at the McArthur River and Key Lake operations expires on December 31, 2013.

• The collective agreement with the bargaining unit employees at the Port Hope conversion facility expires on June 30, 2013.

• BPLP’s collective agreement with the Power Workers’ Union expires on December 31, 2013 and 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.

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.

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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 are examining our entire supply chain 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.

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.

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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, and 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.

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

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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.

Civil unrest

There has been recent civil unrest in the oil producing region of West Kazakhstan. The government has taken action to resolve the underlying concerns and restore stability. Inkai, which is in South Kazakhstan, has not been impacted by the civil unrest. We are monitoring the situation. There is no assurance that Inkai’s operations will not be impacted by civil unrest in the future.

See page 41 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 development project is located. A prohibition or restriction on uranium exploration or mining in the future that interferes with the development of Kintyre 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 operations and exploration 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 operations 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 uranium 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.

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

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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 by 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 (including uranium from dismantling nuclear weapons)

• 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 since 2007.

The table below shows the range in spot prices over the last five years.

Range of spot uranium prices US$/lb of U3O8
	2007		2008		2009		2010		2011
High	$	135.50	$	76.50	$	51.50	$	62.25	$	72.63
Low		75.00		45.50		42.00		40.75		49.13

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Spot UF6 conversion values US$/kg U
	2007		2008		2009		2010		2011
High	$	11.63	$	9.50	$	8.50	$	13.00	$	13.00
Low		8.75		8.00		5.75		5.38		8.00

The next table shows the range in term prices over the last five years.

Range of term uranium prices US$/lb of U3O8
	2007		2008		2009		2010		2011
High	$	95.00	$	95.00	$	69.50	$	66.00	$	71.50
Low		75.00		70.00		61.00		59.00		62.00
Term UF6 conversion values US$/kg U
High	$	12.25	$	12.25	$	12.25	$	15.00	$	16.75
Low		12.25		12.25		11.00		11.00		15.25

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 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.

We use a uranium contracting 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 10 years or more. 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.

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.

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

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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 or development 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 also assume the successful transition to new mining areas

• Cigar Lake assume that development activities are completed successfully

• Inkai assume it receives regulatory approval, approval from our partner and is able to ramp up production to the design capacity rate of 5.2 million pounds.

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.

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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

• delay or lack of success in mining new areas at McArthur River or completing construction activities

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

• 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 and providing uranium conversion services. We rely heavily on a small number of customers to purchase a significant portion of our uranium concentrates and conversion services.

From 2012 through 2014, we expect:

• our five largest customers to account for 38% of our contracted supply of U₃O₈

• our five largest UF₆ conversion customers to account for 44% of our contracted supply of UF₆ conversion services.

We are currently the only commercial supplier of UO₂ used by Canadian Candu heavy water reactors. Our sales to our largest customer accounted for 43% of our UO₂ sales in 2011.

In addition, revenues in 2011 from one customer of our uranium and conversion segments represented $134.7 million (7%) 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.

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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

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, 2011, 95% of our forecast revenue under contract for the period 2012 to 2014 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.

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

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planned. 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 capital and operating costs, estimated 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.

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.

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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 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 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.

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 decommissioning plans for some of our properties with the regulators. We review these plans 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 may conduct a further review of 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.

2011 ANNUAL INFORMATION FORM Page 116

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.

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 120 for more information.

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 and Russian HEU commercial agreement stipulate 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 these 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.

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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. We have received formal demands from the English First River Nation and the Métis Nation of Saskatchewan to consult with and accommodate them when we operate or develop on traditional lands. All aboriginal groups in northern Saskatchewan expect this of us.

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.

The English First River Nation selected lands for designation as Treaty Land Entitlement (TLE) that cover the mineral claims for the Millennium uranium deposit. The Saskatchewan government rejected this selection in December 2008, but the English First River Nation has challenged that rejection in the courts. The TLE process does not affect the rights of our mining joint ventures. It may, however, affect the surface rights and benefits ultimately negotiated as part of the development of Millennium, and we are monitoring developments on the litigation.

Kintyre

To proceed with development of Kintyre in Australia, we must reach an agreement with the Martu, the native land title holders for this property. In 2011, we signed a non-binding memorandum of understanding with the Martu that acknowledges their support in principle for development of the project and outlines a target schedule for finalizing the terms of a comprehensive agreement. Negotiations are ongoing, but we are uncertain whether we will able to ultimately reach an agreement.

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.

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Agreements with some customers may include specific terms limiting 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.

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.

2011 ANNUAL INFORMATION FORM Page 119

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 notes 24 and 31 to the 2011 financial statements.

2011 ANNUAL INFORMATION FORM Page 120

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 9, 2012, we had 394,767,078 common shares outstanding. These were fully paid and non-assessable.

As of February 9, 2012, there were 8,442,385 stock options outstanding to acquire common shares of Cameco under the company’s stock option plan.

In 2011, we granted the following stock options:

• March 1, 2011 - 1,580,069 stock options to acquire common shares of Cameco at an exercise price of $39.53

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• July 1, 2011 - 50,000 stock options to acquire common shares of Cameco at an exercise price of $25.44

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.

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There have been instances in prior years, including 2011, 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.

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. Our investment grade credit ratings reflect the current financial strength of our company.

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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.

We have two 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.

Although we frequently issued commercial paper in the past, we did not have any outstanding commercial paper at February 23, 2012. The table below shows the DBRS and S&P ratings of our commercial paper and senior unsecured debentures:

	DBRS1		S&P2
Commercial paper		R-1 (low)		A-1 (low)3
Senior unsecured debentures		A (low)		BBB+

¹  Current as of February 2012.

²  Current as of December 2011.

³  A-1 (low) is the Canadian National Scale Rating (the Global Scale Rating is A-2).

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” •   the 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.

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 “satisfactory credit quality” •   third highest of 10 available credit ratings
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 •   represents “adequate protection parameters” •   the fourth highest of 10 available credit ratings

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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 in 2011 – there were none

• entered into before 2011 and remain in effect – there are two, which are 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% and due in 2019.

See Senior unsecured debentures, above for more information about these debentures.

By law there are certain other contracts that must be described in an AIF, but we have not entered into any of these kinds of contracts.

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 (CIBC Mellon) and the US (Computershare) for our common shares:

Canada
Canadian Stock Transfer Company Inc.¹ P.O. Box 700, Station B Montreal, Quebec H3B 3K3 US Computershare 480 Washington Blvd. Jersey City, New Jersey United States of America 07310

¹  Canadian Stock Transfer Company Inc. acts as the Administrative Agent for CIBC Mellon Trust Company.

Trading activity

The table below shows the high and low closing prices and trading volume for our common shares on the TSX in 2011.

2011	High ($)		Low ($)		Volume
January		41.91		36.87		22,972,985
February		44.28		39.34		22,711,991
March		40.18		27.70		73,486,731
April		30.15		26.38		26,641,592
May		29.67		25.20		28,454,407
June		28.25		22.64		25,794,461
July		27.05		23.91		23,221,933
August		25.52		20.45		35,007,134
September		23.25		18.28		26,249,525
October		22.87		17.61		31,322,225
November		22.17		17.25		34,440,340
December		19.95		17.60		19,292,596

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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. The board approved an increase in the annual dividend in December 2010 (starting in 2011) and in December 2009 (starting in 2010). Under the policy, in December 2011, the board approved an annual dividend of $0.40 per share (starting in 2012).

	2011		2010		2009
Cash dividends	$	0.40	$	0.28	$	0.24

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Governance

Directors

Director	Board committees	Principal occupation or employment
Daniel Camus Paris, France Director since 2011	Audit Safety, health and environment Human resources and compensation	Corporate director as of 2011 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 (Chair) Human resources and compensation	Corporate director as of 2006 1990 to December 2005 – managing partner of the Toronto office of PricewaterhouseCoopers LLP
Joe Colvin Santa Fe, New Mexico Director since 1999	Safety, health and environment (Chair) Nominating, corporate governance and risk	June 2011 to present – Past-President of American Nuclear Society June 2010 to June 2011 – President of American Nuclear Society February 2005 to present – Corporate director and president emeritus of the Nuclear Energy Institute
James Curtiss Brookeville, Maryland, USA Director since 1994	Human resources and compensation (Chair) Nominating, corporate governance and risk	April 2008 to present – principal of Curtiss law 1993 to March 2008 – lawyer, partner, Winston & Strawn LLP
Donald Deranger Prince Albert, Saskatchewan, Canada Director since 2009	Reserves oversight Safety, health and environment	2003 to present – Athabasca Vice Chief of the Prince Albert Grand Council 2001 to present – President of Points Athabasca Contracting LP
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 June 2004 to January 2007 – Executive Vice-President, mining business unit, AREVA
James Gowans Toronto, Ontario, Canada Director since 2009	Reserves oversight Safety, health and environment Nominating, corporate governance and risk	January 2011 to present – Managing Director, Debswana Diamond Company March 2010 to December 2010 – COO and Chief Technical Officer of DeBeers SA April 2006 to December 2010 – CEO of DeBeers Canada Inc. 2002 to 2006 – Senior Vice-President and COO of PT Inco in Indonesia
Nancy Hopkins Saskatoon, Saskatchewan, Canada Director since 1992	Nominating, corporate governance and risk (Chair) Audit	1984 to present – Lawyer, partner, McDougall Gauley LLP (Gauley & Company merged with McDougall Ready to form McDougall Gauley as of January 2001)
Oyvind Hushovd Kristiansand S, Norway Director since 2003	Audit Human resources and compensation Reserves oversight	June 2005 to present – Corporate director May 2003 to May 2005 – Chairman and Chief Executive Officer of Gabriel Resources Ltd.
Anne McLellan Edmonton, Alberta, Canada Director since 2006	Human resources and compensation Nominating, corporate governance and risk Safety, health and environment	July 2006 to present – Distinguished Scholar in Residence at Alberta Institute for American Studies, University of Alberta June 2006 to present – Lawyer, counsel at Bennett Jones LLP 1993 to 2006 – cabinet minister in various portfolios with the Canadian government, most

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		recently as Deputy Prime Minister of Canada from 2003 to 2006
Neil McMillan Saskatoon, Saskatchewan, Canada Director since 2002	Reserves oversight (Chair) Audit Human resources and compensation	March 2004 to present – President and Chief Executive Officer, Claude Resources Inc.
Victor Zaleschuk Calgary, Alberta, Canada Director since 2001	Reserves oversight	November 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
Victor Zaleschuk Chair of the Board Calgary, Alberta, Canada	November 2001 to present – Corporate director
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 June 2004 to January 2007 – Executive Vice-President, mining business unit, AREVA
Gary Chad Senior Vice-President, Governance, Law 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
Ken Seitz Senior Vice-President, Marketing, Exploration and Corporate Development 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 1999 to 2007 – Vice-President, Fuel Services
Alice Wong Senior Vice-President, Corporate Services Saskatoon, Saskatchewan, Canada	Assumed current position July 2011 October 2008 to July 2011 – Vice-President, Safety, Health, Environment, Quality and Regulatory Relations May 2005 to September 2008 – Vice-President, Investor, Corporate & Government Relations

To our knowledge, the total number of common shares that the directors and officers as a group either: (i) beneficially owned; or (ii) exercised direction or control over, directly or indirectly was 210,310 as at February 9, 2012. 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

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securities, nor their associates or affiliates, have 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.

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.

About the audit committee

Audit committee charter

See appendix A for a copy of the audit committee charter. You can also find a copy on our website (cameco.com/responsibility/governance/board_committees).

Composition of the audit committee

The committee is made up of five members: John Clappison (chair), Daniel Camus, Nancy Hopkins, Oyvind Hushovd and Neil McMillan. Each member is independent and financially literate using criteria that meet the standards of the Canadian Securities Administrators as set out in Multilateral Instrument 52-110.

Relevant education and experience

John Clappison, a corporate director, is the former managing partner of the Toronto office of PricewaterhouseCoopers LLP. He currently serves on three other publicly traded companies, and the boards of other private and not-for-profit organizations. Cameco’s board has approved Mr. Clappison sitting on four audit committees of publicly traded companies, including Cameco. Mr. Clappison is a chartered accountant and a Fellow of the Institute of Chartered Accountants of Ontario.

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 subsidiaries around the world. He currently serves on the boards of four other publicly traded companies, on two of which he is a member of their audit

2011 ANNUAL INFORMATION FORM Page 129

committees and one 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. Mr. Camus received his PhD in Economics from Sorbonne University, an MBA in finance and economics from the Institute d’Études Politiques de Paris and a masters of economics degree from Nancy University in France.

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 two other publicly traded companies, the board of governors of the University of Saskatchewan, the board of the Saskatoon Airport Authority and the CPP Investment Board. She formerly served on the board of the Canadian Institute of Chartered Accountants. Ms. Hopkins has a Bachelor of Commerce degree and a Bachelor of Laws degree from the University of Saskatchewan.

Oyvind Hushovd, a corporate director, is the former Chair and Chief Executive Officer of Gabriel Resources Ltd., a Canadian-based precious metals exploration and development company, retiring in 2005. Prior to that he was the President and Chief Executive Officer of Falconbridge Limited from 1996 to 2002. He currently serves on the boards of two other publicly traded companies and three private companies. Mr. Hushovd received a Master of Economics and Business Administration degree from the Norwegian School of Business and a Master of Law degree from the University of Oslo.

Neil McMillan is the President and Chief Executive Officer of Claude Resources Inc., a gold mining and exploration company based in Saskatoon, Saskatchewan. Prior to joining Claude Resources Inc., Mr. McMillan worked for RBC Dominion Securities as a registered representative and the Saskatoon branch manager. He currently serves on the boards of two other publicly traded companies (including Claude Resources Inc.) and previously sat on the board of Atomic Energy Canada Ltd. Mr. McMillan received a Bachelor of Arts degree in History and Sociology from the University of Saskatchewan.

Auditors’ fees

The table below shows the fees we paid to the external auditors for services in 2011 and 2010:

	2011 ($)		% of total fees (%)		2010 ($)		% of total fees (%)
Audit fees
Cameco		1,773,600		61.4		1,697,700		62.6
Subsidiaries		400,700		13.9		256,200		9.5
Total audit fees		2,174,300		75.3		1,953,900		72.1
Audit-related fees
Translation services		—		—		44,500		1.7
Accounting advisory		195,100		6.8		273,400		10.1
Pensions and other		21,000		0.7		20,000		0.7
Total audit-related fees		216,100		7.5		337,900		12.5
Tax fees
Compliance		62,500		2.2		199,200		7.3
Planning and advice		433,400		15.0		219,500		8.1
Total tax fees		495,900		17.2		418,700		15.4
All other fees		—		—		—		—
Total fees		2,886,300		100.0		2,710,500		100.0

Approving services

The audit committee must pre-approve all services the external auditors will provide to make sure they remain independent. This is according to our audit committee charter and consistent with our corporate governance

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practices. The audit 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 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 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 2011 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 are listed under Mineral reserves and resources starting on page 73. 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 committee of the board of directors

Mandate

Purpose

The primary purpose of the audit 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) 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 committees of more than three public companies (including Cameco’s) without the approval of the board.

2011 ANNUAL INFORMATION FORM Page 132

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.

2011 ANNUAL INFORMATION FORM Page 133

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 represent 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 represent 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

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controls, and obtain reports on significant findings and recommendations, together with management responses.

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

2011 ANNUAL INFORMATION FORM Page 135

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

(c) annually review and evaluate senior members of the external audit team, including their expertise and qualifications. In making this evaluation, the audit 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.

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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.

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. 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 summarising 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.

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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.

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EX-99.2

EXHIBIT 99.2

Cameco Corporation

2011 Consolidated Audited Financial Statements

February 8, 2012

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 judgment, 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” 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, 2011.

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 financial statements, the report of the shareholders’ auditors, and 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
Chief Executive Officer	Senior Vice-President and Chief Financial Officer
February 8, 2012	February 8, 2012

1

INDEPENDENT AUDITORS’ REPORT OF REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders 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, 2011, December 31, 2010 and January 1, 2010, the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for the years ended December 31, 2011 and December 31, 2010, 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 and the standards of the Public Company Accounting Oversight Board (United States). 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, 2011, December 31, 2010 and January 1, 2010, and its consolidated results from operations and its consolidated cash flows for the years ended December 31, 2011 and December 31, 2010 in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Original signed by KPMG LLP

Chartered Accountants

Saskatoon, Canada

February 8, 2012

2

Consolidated Statements of Earnings

For the years ended December 31 ($Cdn thousands, except per share amounts)	Note	2011			2010
Revenue from products and services		$	2,384,404		$	2,123,655
Cost of products and services sold			1,333,449			1,113,963
Depreciation and amortization			274,835			238,308
Cost of sales			1,608,284			1,352,271
Gross profit			776,120			771,384
Administration			157,476			154,698
Exploration			95,924			95,796
Research and development			4,514			4,794
Cigar Lake remediation			4,363			16,633
Loss on disposal of assets			7,602			107
Earnings from operations			506,241			499,356
Finance costs	22		(73,668	)		(86,179	)
Gains (losses) on derivatives	29		(4,417	)		75,183
Finance income			24,547			20,894
Share of loss from equity-accounted investees	13		(7,233	)		(4,176	)
Other income	23		4,920			4,388
Earnings before income taxes			450,390			509,466
Income tax expense	24		11,755			3,427
Net earnings		$	438,635		$	506,039
Net earnings (loss) attributable to:
Equity holders		$	450,404		$	516,391
Non-controlling interest			(11,769	)		(10,352	)
Net earnings		$	438,635		$	506,039
Earnings per common share attributable to equity holders
Basic	25	$	1.14		$	1.31
Diluted	25	$	1.14		$	1.31

See accompanying notes to consolidated financial statements.

3

Consolidated Statements of Comprehensive Income

For the years ended December 31 ($Cdn thousands, except per share amounts)	Note	2011			2010
Net earnings		$	438,635		$	506,039
Other comprehensive income (loss), net of taxes	24
Exchange differences on translation of foreign operations			38,635			6,435
Gains on derivatives designated as cash flow hedges			7,954			12,035
Gains on derivatives designated as cash flow hedges transferred to net earnings			(18,700	)		(71,186	)
Unrealized gains on available-for-sale securities			272			2,125
Gains on available-for-sale securities transferred to net earnings			(1,917	)		(2,557	)
Defined benefit plan actuarial losses			(104,037	)		(108,982	)
Other comprehensive loss, net of taxes			(77,793	)		(162,130	)
Total comprehensive income		$	360,842		$	343,909
Other comprehensive income (loss) attributable to:
Equity holders		$	(81,985	)	$	(176,168	)
Non-controlling interest			4,192			14,038
Other comprehensive loss for the period		$	(77,793	)	$	(162,130	)
Total comprehensive income (loss) attributable to:
Equity holders		$	368,419		$	340,223
Non-controlling interest			(7,577	)		3,686
Total comprehensive income for the period		$	360,842		$	343,909

See accompanying notes to consolidated financial statements.

4

Consolidated Statements of Financial Position

As at December 31 ($Cdn thousands)	Note	2011		2010		Jan 1/10
Assets
Current assets
Cash and cash equivalents		$	399,279	$	376,621	$	1,101,229
Short-term investments	7		804,141		883,032		202,836
Accounts receivable	8		612,181		448,479		448,586
Current tax assets			31,388		42,190		—
Inventories	9		493,875		533,090		444,837
Supplies and prepaid expenses			182,037		190,079		169,005
Current portion of long-term receivables, investments and other	12		62,433		95,271		158,011
Total current assets			2,585,334		2,568,762		2,524,504
Property, plant and equipment	10		4,532,107		3,954,647		3,716,774
Intangible assets	11		98,954		94,270		97,713
Long-term receivables, investments and other	12		283,818		338,851		397,490
Investments in equity-accounted investees	13		220,226		220,430		222,564
Deferred tax assets	24		81,392		25,594		24,011
Total non-current assets			5,216,497		4,633,792		4,458,552
Total assets		$	7,801,831	$	7,202,554	$	6,983,056
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	14	$	457,307	$	389,959	$	494,081
Current tax liabilities			39,330		35,042		31,143
Short-term debt	15		91,703		85,588		87,506
Dividends payable			39,475		27,605		23,570
Current portion of finance lease obligation	17		14,852		13,177		11,629
Current portion of other liabilities	18		50,495		28,228		29,297
Current portion of provisions	19		14,857		19,394		16,301
Total current liabilities			708,019		598,993		693,527
Long-term debt	16		801,271		794,483		793,842
Finance lease obligation	17		130,982		145,834		159,011
Other liabilities	18		528,264		402,949		298,391
Provisions	19		519,625		365,573		340,528
Deferred tax liabilities	24		8,165		26,270		107,657
Total non-current liabilities			1,988,307		1,735,109		1,699,429
Shareholders’ equity
Share capital			1,842,289		1,833,257		1,809,861
Contributed surplus			155,757		142,376		131,577
Retained earnings			2,874,973		2,690,184		2,392,940
Other components of equity			46,548		24,496		91,682
Total shareholders’ equity attributable to equity holders			4,919,567		4,690,313		4,426,060
Non-controlling interest			185,938		178,139		164,040
Total shareholders’ equity			5,105,505		4,868,452		4,590,100
Total liabilities and shareholders’ equity		$	7,801,831	$	7,202,554	$	6,983,056

Commitments and contingencies [notes 19,24,31]

See accompanying notes to consolidated financial statements.

Approved by the board of directors

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

5

Consolidated Statements of Changes in Equity

($Cdn Thousands)

	Attributable to equity holders
	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, 2011	$	1,833,257	$	142,376		$	2,690,184		$	(7,603	)	$	30,306		$	1,793		$	4,690,313		$	178,139		$	4,868,452
Net earnings		—		—			450,404			—			—			—			450,404			(11,769	)		438,635
Total other comprehensive income		—		—			(104,037	)		34,443			(10,746	)		(1,645	)		(81,985	)		4,192			(77,793	)
Total comprehensive income for the year		—		—			346,367			34,443			(10,746	)		(1,645	)		368,419			(7,577	)		360,842
Stock-based compensation		—		19,492			—			—			—			—			19,492			—			19,492
Share options exercised		9,032		(6,111	)		—			—			—			—			2,921			—			2,921
Dividends		—		—			(157,887	)		—			—			—			(157,887	)		—			(157,887	)
Change in ownership interests in subsidiaries		—		—			(3,691	)		—			—			—			(3,691	)		3,883			192
Transactions with owners - contributed equity		—		—			—			—			—			—			—			11,493			11,493
Balance at December 31, 2011	$	1,842,289	$	155,757		$	2,874,973		$	26,840		$	19,560		$	148		$	4,919,567		$	185,938		$	5,105,505
Balance at January 1, 2010		1,809,861		131,577			2,392,940			—			89,457			2,225			4,426,060			164,040			4,590,100
Net earnings		—		—			516,391			—			—			—			516,391			(10,352	)		506,039
Total other comprehensive income		—		—			(108,982	)		(7,603	)		(59,151	)		(432	)		(176,168	)		14,038			(162,130	)
Total comprehensive income for the year		—		—			407,409			(7,603	)		(59,151	)		(432	)		340,223			3,686			343,909
Stock-based compensation		—		16,086			—			—			—			—			16,086			—			16,086
Share options exercised		23,396		(5,287	)		—			—			—			—			18,109			—			18,109
Dividends		—		—			(110,165	)		—			—			—			(110,165	)		—			(110,165	)
Transactions with owners - contributed equity		—		—			—			—			—			—			—			10,413			10,413
Balance at December 31, 2010	$	1,833,257	$	142,376		$	2,690,184		$	(7,603	)	$	30,306		$	1,793		$	4,690,313		$	178,139		$	4,868,452

See accompanying notes to consolidated financial statements.

6

Consolidated Statements of Cash Flows

For the years ended December 31 ($Cdn thousands)	Note	2011			2010
Operating activities
Net earnings		$	438,635		$	506,039
Adjustments for:
Depreciation and amortization			274,835			238,308
Deferred charges			(7,869	)		(33,369	)
Unrealized losses on derivatives			60,558			25,561
Share-based compensation	27		19,492			16,086
Loss on disposal of assets			7,602			107
Finance costs	22		73,668			86,179
Finance income			(24,547	)		(20,894	)
Share of loss from equity-accounted investees	13		7,233			4,176
Other income	23		(4,920	)		(4,388	)
Income tax expense	24		11,755			3,427
Interest received			23,718			32,310
Income taxes paid			(60,744	)		(74,827	)
Income taxes refunded			30,128			11,601
Other operating items	26		(117,867	)		(269,054	)
Net cash provided by operations			731,677			521,262
Investing activities
Additions to property, plant and equipment	10		(647,210	)		(430,582	)
Decrease (increase) in short-term investments			79,228			(680,346	)
Decrease in long-term receivables, investments and other			39,890			9,453
Proceeds from sale of property, plant and equipment			62			1,437
Net cash used in investing			(528,030	)		(1,100,038	)
Financing activities
Increase in debt			12,105			1,896
Decrease in debt			(14,713	)		(11,629	)
Interest paid			(60,533	)		(53,859	)
Contributions from non-controlling interest			13,212			9,811
Proceeds from issuance of shares, stock option plan			7,339			18,109
Dividends paid			(146,017	)		(106,132	)
Net cash used in financing			(188,607	)		(141,804	)
Increase (decrease) in cash during the period			15,040			(720,580	)
Exchange rate changes on foreign currency cash balances			7,618			(4,028	)
Cash and cash equivalents at beginning of period			376,621			1,101,229
Cash and cash equivalents at end of period		$	399,279		$	376,621
Cash and cash equivalents is comprised of:
Cash		$	49,548		$	100,752
Cash equivalents			349,731			275,869
		$	399,279		$	376,621

See accompanying notes to consolidated financial statements.

7

Notes to Consolidated Financial Statements

For the years ended December 31, 2011 and 2010

($Cdn thousands except per share amounts and as noted)

1. Cameco Corporation

Cameco Corporation is incorporated under the Canada Business Corporations Act. The address of its registered office is 2121 11^th Street West, Saskatoon, Saskatchewan, S7M 1J3. The consolidated financial statements as at and for the year ended December 31, 2011 comprise Cameco Corporation and its subsidiaries (collectively, the “Company” or “Cameco”) and the Company’s interest in associates and joint ventures. The Company is primarily engaged in the exploration for and the development, mining, refining, conversion and fabrication 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 are the Company’s first consolidated financial statements prepared under IFRS and IFRS 1, First-time Adoption of International Financial Reporting Standards (“IFRS 1”), has been applied.

The Company’s consolidated financial statements for the year ended December 31, 2010 were previously prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). As these are the Company’s first consolidated financial statements in accordance with IFRS, the comparative figures for 2010 were revised and an explanation of how the transition from Canadian GAAP to IFRS has affected the financial statements of the Company is provided in note 3.

These consolidated financial statements were authorized for issuance by the Company’s Board of Directors on February 8, 2012.

(b) Basis of Presentation

These consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. All financial information presented in Canadian dollars has been rounded to the nearest thousand except where otherwise noted.

The consolidated financial statements have been prepared on the historical cost basis except for the following material items in the statement of financial position: derivative financial instruments are measured at fair value, available-for-sale financial assets are measured at fair value, liabilities for cash-settled share-based payment arrangements are measured at fair value and the defined benefit asset is recognized as plan assets, plus unrecognized past service cost, 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 6.

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 and to all periods presented in these consolidated financial statements.

8

(c) Consolidation Principles

(i) Business Combinations

Acquisitions on or after January 1, 2010

The acquisition method of accounting is used to account for the acquisition of subsidiaries by the Company. For acquisitions on or after January 1, 2010, 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.

Acquisitions before January 1, 2010

As part of its transition to IFRS, the Company elected, under IFRS 1, to restate only those business combinations that occurred on or after January 1, 2010.

(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 de-consolidated from the date that control ceases.

(iii) Investments in Associates

Associates are those entities over which the Company has significant influence, but not control, over the financial and operating policies. Significant influence is presumed to exist when the Company holds between 20 and 50 percent of the voting power of another entity, but can also arise where the Company holds less than 20 percent 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) Interests in Joint Ventures

A joint venture can take the form of a jointly controlled entity, jointly controlled operation or jointly controlled asset. All joint ventures involve a contractual arrangement that establishes joint control. Cameco’s joint ventures consist of jointly controlled entities and jointly controlled assets.

9

A jointly controlled entity is an entity in which Cameco shares joint control over the strategic financial and operating decisions with one or more venturers through the establishment of a corporation, partnership or other entity. A jointly controlled entity operates in the same way as other entities, controlling the assets of the joint venture, earning its own income and incurring its own liabilities and expenses. Interests in jointly controlled entities are accounted for using the proportionate consolidation method, whereby the Company’s proportionate interest in the assets, liabilities, revenues and expenses of jointly controlled entities are recognised within each applicable line item of the consolidated financial statements. The share of jointly controlled entities’ results is recognised in the Company’s consolidated financial statements from the date that joint control commences until the date at which it ceases.

A jointly controlled asset involves contractual arrangements with other participants to engage in joint activities that do not give rise to a jointly controlled entity. These arrangements involve joint control of one or more of the assets acquired or contributed for the purpose of the joint venture. Each venturer receives a share of the output from the assets and bears an agreed upon share of the expenses rather than deriving returns from an interest in a separate entity. The consolidated financial statements of the Company include its share of the assets in such joint ventures, 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, which are usually in proportion to the Company’s interest in the jointly controlled assets.

(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 consolidated financial statements. Unrealized gains arising from transactions with equity-accounted investees and joint ventures are eliminated against the investment to the extent of the Company’s interest in the associate or the joint venture. 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 jointly controlled entities 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 date. The income 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 reserve 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, are recognized in other comprehensive income and presented within equity in the foreign currency translation account.

10

(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) 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.

(g) 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	4 - 15 years
Furniture and fixtures	3 - 10 years
Other	3 - 5 years

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.

Depreciation methods, useful lives and residual values are reviewed at each financial year end and adjusted if appropriate.

11

(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 operation 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.

(vi) Leased assets

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.

(h) Intangible Assets

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.

Finite-lived intangible assets are amortized over the estimated production profile of the business unit to which they relate, since this most closely reflects the expected pattern of realization of the future economic benefits embodied in the asset. Amortization methods and useful lives are reviewed at each financial year end and adjusted if appropriate.

(i) 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 statement 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.

(j) 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.

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.

12

(k) Impairment

(i) Financial Assets

A financial asset not carried at fair value through profit or loss is assessed at each reporting date to determine whether there is objective evidence that it is impaired. A financial asset is impaired if objective evidence indicates that a loss event has occurred after the initial recognition of the asset, and that the loss event had a negative effect on the estimated future cash flows of that asset.

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 investment securities 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. Changes in impairment provisions attributable to time value are reflected as a component of finance costs.

If, in a subsequent period, the fair value of an impaired available-for-sale security increases and the increase can be related objectively to an event occurring after the impairment loss was recognized in profit or loss, then the impairment loss is reversed, with the amount of the reversal recognized in profit or loss.

(ii) Non-Financial Assets

The carrying amounts of Cameco’s non-financial assets, other than inventories and deferred tax 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.

The recoverable amount of an asset or cash-generating unit (“CGU”) is the greater of its value in use and its fair value less costs to sell.

Fair value is determined as the amount that would be obtained from the sale of the asset in an arm’s length transaction between knowledgeable and willing parties. Fair value for mineral assets is generally determined as the present value of the estimated future cash flows expected to arise from the continued use of the asset, including any expansion prospects, and its eventual disposal, using assumptions that an independent market participant may take into account. These cash flows are discounted by an appropriate discount rate to arrive at a net present value of the asset.

Value in use is determined as the present value of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its eventual disposal. Value in use is determined by applying assumptions specific to the Company’s continued use and cannot take into account future development. These assumptions are different than those used in calculating fair value and consequently the value in use calculation is likely to give a different result (usually lower) than a fair value calculation. The estimated future cash flows are 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. For the purpose of impairment testing, assets that cannot be tested individually are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets.

The Company’s corporate assets do not generate separate cash inflows. If there is an indication that a corporate asset may be impaired, then the recoverable amount is determined for the CGU to which the corporate asset belongs.

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 units, and then to reduce the carrying amounts of the other assets in the unit (group of units) on a pro rata basis.

13

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.

(l) 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 are charged against earnings as incurred and include researching and analyzing existing exploration data, conducting geological studies, exploratory drilling and sampling and compiling pre-feasibility and feasibility studies.

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.

(m) 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 or 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 license 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 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.

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 units-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 on an annual basis for changes to obligations or 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.

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(n) 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 statement 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, together with adjustments for unrecognized past service costs. The defined benefit obligation is calculated annually, by qualified actuaries using the projected unit credit method pro-rated 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 in earnings on a straight-line basis over the average period until the benefits become vested. To the extent that the benefits vest immediately, the expense 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 healthcare 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.

(iii) Short-Term Employee Benefits

Short-term employee 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 voluntary redundancy in exchange for these benefits. Cameco recognizes termination benefits as an expense when the Company is demonstrably committed, without realistic possibility of withdrawal, to a formal detailed plan to either terminate employment before the normal retirement date, or to provide termination benefits as a result of an offer made to encourage voluntary redundancy. Termination benefits for voluntary redundancies are recognized as an expense if the Company has made an offer, it is probable that the offer will be accepted and the number of acceptances can be estimated reliably. If benefits are payable more than 12 months after the reporting period, they are discounted to their present value.

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(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 re-measured 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.

(o) 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.

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 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.

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(p) Financial Instruments

(i) Financial Assets and Financial Liabilities

Financial assets include cash and cash equivalents, trade receivables, other receivables, loans, other investments and derivative financial instruments. The Company determines the classification of its financial assets at initial recognition and records the assets at the fair value of consideration paid. Subsequently, financial assets are carried at fair value or amortized cost less impairment charges. Where non-derivative financial assets are carried at fair value, gains and losses on remeasurement are recognized directly in equity unless the financial assets have been designated as being held at fair value through profit or loss, in which case the gains and losses are recognized directly in net earnings.

All financial liabilities are initially recognized at the fair value of consideration received net of transaction costs and subsequently carried at amortized cost. Financial liabilities include trade and other payables, debt and derivative financial instruments. The Company determines the classification of its financial liabilities at initial recognition.

The Company has the following non-derivative financial assets: loans and receivables and available-for-sale financial assets.

Loans and receivables

Loans and receivables are financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are carried at amortized cost using the effective interest method if the time value of money is significant. This category of financial assets includes trade and other receivables.

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

Available-for-sale financial assets

Available-for-sale financial assets are non-derivative financial assets that are not classified as loans and receivables. The Company’s investments in equity securities and certain debt securities are classified as available-for-sale financial assets. Subsequent to initial recognition, they are measured at fair value, with gains or losses recognized within other comprehensive income. Accumulated changes in fair value are recorded as a separate component of equity until the investment is derecognized or impaired, then the cumulative gain or loss in other comprehensive income is transferred to profit or loss.

The Company has the following non-derivative financial liabilities: loans and accounts payable. Such liabilities are carried at amortized cost using the effective interest method if the time value of money is significant.

(ii) Derivative Financial Instruments

The Company holds derivative financial and commodity instruments to reduce exposure to fluctuations in foreign currency exchange rates, interest rates and commodity prices. Except for those designated as hedging instruments, all derivative instruments are recorded at fair value in the consolidated statements of financial position, with 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 balance sheet 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.

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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.

(q) Income Tax

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

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. Accrued interest and penalties for uncertain tax positions are recognized in the period in which uncertainties are identified.

(r) 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.

(s) 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.

(t) 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 operating decision maker.

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. Explanation of Transition to IFRS

As stated in note 2(a), these are the Company’s first consolidated financial statements prepared in accordance with IFRS. The accounting policies set out in note 2 have been applied for all periods presented in the consolidated financial statements for the year ended December 31, 2011.

In preparing its opening IFRS statement of financial position, the Company has adjusted amounts previously reported in financial statements prepared in accordance with Canadian GAAP. An explanation of how the transition from Canadian GAAP to IFRS has affected the Company’s financial statements is set out in the following tables and the notes that accompany the tables.

Elected IFRS 1 exemptions applicable to the presentation of the internal opening IFRS financial position

Cameco has elected and applied the following IFRS 1 exemptions:

(i) Borrowing costs – IFRS 1 provides the option to apply IAS 23, Borrowing Costs (“IAS 23”), prospectively from the transition date to IFRS (January 1, 2010), or from a particular pre-transition date elected by the first time adopter. Borrowing costs may be capitalized on qualifying assets for which the commencement date for capitalization was on or after the date selected. The Company elected to apply IAS 23 prospectively from the date of transition to IFRS. Based on this election, Cameco expensed the borrowing costs capitalized before January 1, 2010 under Canadian GAAP and will capitalize borrowing costs incurred on qualifying assets for which the commencement date for capitalization is subsequent to January 1, 2010.

(ii) Decommissioning liabilities – The application of IFRIC 1, Changes in Existing Decommissioning, Restoration and Similar Liabilities (“IFRIC 1”), would require the Company to recalculate, retrospectively, the effect of each change in its reclamation provision prior to the date of transition, along with the impact on the related assets and depreciation. IFRS 1 provides the option to instead measure the liability and related depreciation effects as at the date of transition to IFRS. Cameco has elected to apply this exemption and calculated the impact on the statement of financial position as of January 1, 2010.

(iii) Employee benefits – IAS 19, Employee Benefits (“IAS 19”), requires extensive disclosures in respect of defined benefit plans. IFRS 1 provides an optional exemption that permits the first-time adopter to elect to provide these disclosures prospectively from the date of transition. The Company has elected to apply this exemption and will provide the full disclosures required by IAS 19 in its first annual consolidated financial statements prepared under IFRS.

(iv) Share-based compensation – IFRS 2, Share-Based Payments (“IFRS 2”), encourages application of its provisions to liabilities arising from cash-settled transactions that were settled before the transition date but only requires application to those transactions that will be settled after the transition date. The Company elected to apply IFRS 2 only to liabilities arising from share-based compensation transactions that existed at January 1, 2010.

(v) Business combinations – The application of IFRS 3, Business Combinations (“IFRS 3”), requires the restatement of all past business combinations in accordance with IFRS 3. IFRS 1 provides the option to apply IFRS 3 prospectively from the transition date, or from a particular pre-transition date elected by the Company. The Company elected to not restate any past business combinations and to apply IFRS 3 prospectively from the transition date.

(vi) Cumulative translation differences – IAS 21, The Effects of Changes in Foreign Exchange Rates, would require the Company to calculate currency translation differences retrospectively, from the date a subsidiary or associate was formed or acquired. IFRS 1 provides the option of resetting cumulative translations gains and losses to zero at the transition date. The Company elected to reset cumulative translations losses to zero through opening retained earnings at the transition date.

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Reconciliation of Equity at January 1, 2010 and December 31, 2010
	Cdn GAAP		Jan 1, 2010 effect of transition			IFRS		Cdn GAAP			Dec 31, 2010 effect of transition			IFRS
Assets
Current assets
Cash and cash equivalents	$	1,101,229	$	—		$	1,101,229	$	376,621		$	—		$	376,621
Short-term investments		202,836		—			202,836		883,032			—			883,032
Accounts receivable (a)		446,722		1,864			448,586		447,404			1,075			448,479
Current tax assets		—		—			—		42,190			—			42,190
Inventories (b),(d)		453,224		(8,387	)		444,837		542,526			(9,436	)		533,090
Supplies and prepaid expenses		169,005		—			169,005		190,079			—			190,079
Current portion of long-term receivables, and other		158,011		—			158,011		95,271			—			95,271
Total current assets		2,531,027		(6,523	)		2,524,504		2,577,123			(8,361	)		2,568,762
Property, plant and equipment (a),(b),(c),(d),(e),(k)		4,068,103		(351,329	)		3,716,774		4,337,809			(383,162	)		3,954,647
Intangible assets		97,713		—			97,713		94,270			—			94,270
Long-term receivables, investments, other (a),(f),(g)		664,001		(266,511	)		397,490		625,000			(286,149	)		338,851
Investments in equity-accounted investees (f),(h)		—		222,564			222,564		—			220,430			220,430
Deferred tax assets (p),(q),(r)		33,017		(9,006	)		24,011		37,166			(11,572	)		25,594
Total non-current assets		4,862,834		(404,282	)		4,458,552		5,094,245			(460,453	)		4,633,792
Total assets	$	7,393,861	$	(410,805	)	$	6,983,056	$	7,671,368		$	(468,814	)	$	7,202,554
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities (a),(i)	$	492,777	$	1,304		$	494,081	$	386,396		$	3,563		$	389,959
Current tax liabilities		31,143		—			31,143		35,042			—			35,042
Short-term debt		87,506		—			87,506		85,588			—			85,588
Dividends payable		23,570		—			23,570		27,605			—			27,605
Current portion of finance lease obligation		11,629		—			11,629		13,177			—			13,177
Current portion of other liabilities		29,297		—			29,297		28,228			—			28,228
Current portion of provisions (a),(b),(j),(k),(l)		—		16,301			16,301		—			19,394			19,394
Deferred tax liabilities (p),(q),(r)		87,135		(87,135	)		—		28,674			(28,674	)		—
Total current liabilities		763,057		(69,530	)		693,527		604,710			(5,717	)		598,993
Long-term debt		793,842		—			793,842		794,483			—			794,483
Finance lease obligation		159,011		—			159,011		145,834			—			145,834
Provision for reclamation (j)		258,277		(258,277	)		—		279,653			(279,653	)		—
Other liabilities (a),(g),(j)		244,433		53,958			298,391		244,179			158,770			402,949
Provisions (a),(b),(j),(k),(l)		—		340,528			340,528		—			365,573			365,573
Deferred tax liabilities (p),(q),(r)		167,373		(59,716	)		107,657		208,044			(181,774	)		26,270
Total non-current liabilities		1,622,936		76,493			1,699,429		1,672,193			62,916			1,735,109
Minority interest (o)		164,040		(164,040	)		—		178,139			(178,139	)		—
Shareholders’ equity
Share capital (m)		1,512,461		297,400			1,809,861		1,535,857			297,400			1,833,257
Contributed surplus		131,577		—			131,577		142,376			—			142,376
Retained earnings (s)		3,158,506		(765,566	)		2,392,940		3,563,089			(872,905	)		2,690,184
Other components of equity (b),(d),(g),(h),(k),(n),(p),(r)		41,284		50,398			91,682		(24,996	)		49,492			24,496
Total shareholders’ equity attributable to equity holders		4,843,828		(417,768	)		4,426,060		5,216,326			(526,013	)		4,690,313
Non-controlling interest (o)		—		164,040			164,040		—			178,139			178,139
Total shareholders’ equity		4,843,828		(253,728	)		4,590,100		5,216,326			(347,874	)		4,868,452
Total liabilities and shareholders’ equity	$	7,393,861	$	(410,805	)	$	6,983,056	$	7,671,368		$	(468,814	)	$	7,202,554

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Reconciliation of Total Comprehensive Income for 2010
	Cdn GAAP			Dec 31, 2010 effect of transition			IFRS
Revenue from products and services	$	2,123,655		$	—		$	2,123,655
Products and services sold (a),(l)		1,127,879			(13,916	)		1,113,963
Depreciation and amortization (a),(b),(c),(d),(e),(k)		251,547			(13,239	)		238,308
Cost of sales		1,379,426			(27,155	)		1,352,271
Gross profit		744,229			27,155			771,384
Administration (g),(i)		155,810			(1,112	)		154,698
Exploration		95,796			—			95,796
Research and development		4,794			—			4,794
Cigar Lake remediation		16,633			—			16,633
Gain on sale of assets		107			—			107
Earnings from operations		471,089			28,267			499,356
Finance costs (b),(c),(l)		(24,368	)		(61,811	)		(86,179	)
Gains on derivatives		75,183			—			75,183
Finance income		20,894			—			20,894
Share of loss from equity-accounted investees (h)		(15,538	)		11,362			(4,176	)
Other income		4,388			—			4,388
Earnings before income taxes		531,648			(22,182	)		509,466
Income tax expense (p),(q),(r)		27,251			(23,824	)		3,427
Net earnings	$	504,397		$	1,642		$	506,039
Net earnings (loss) attributable to:
Equity holders	$	514,749		$	1,642		$	516,391
Non-controlling interest		(10,352	)		—			(10,352	)
Net earnings	$	504,397		$	1,642		$	506,039
Basic earnings per common share	$	1.31		$	—		$	1.31
Diluted earnings per common share	$	1.30		$	—		$	1.31
Net earnings	$	504,397		$	1,642		$	506,039
Other comprehensive income (loss), net of taxes
Unrealized foreign currency translation gains (losses)		7,342			(907	)		6,435
Gains on derivatives designated as cash flow hedges		12,035			—			12,035
Gains on derivatives designated as cash flow hedges transferred to net earnings		(71,186	)		—			(71,186	)
Unrealized losses on available-for-sale securities		2,125			—			2,125
Losses on available-for-sale securities transferred to net earnings		(2,557	)		—			(2,557	)
Defined benefit plan actuarial losses (a),(g),(p)		—			(108,982	)		(108,982	)
Other comprehensive loss, net of taxes		(52,241	)		(109,889	)		(162,130	)
Total comprehensive income (loss), net of taxes	$	452,156		$	(108,247	)	$	343,909
Total comprehensive income (loss) attributable to:
Equity holders	$	448,470		$	(108,247	)	$	340,223
Non-controlling interest		3,686			—			3,686
Total comprehensive income (loss)	$	452,156		$	(108,247	)	$	343,909

21

Notes to the reconciliations

The impact on deferred tax of the adjustments described below is set out in note (p).

a) As a result of BPLP also transitioning to IFRS, Cameco has recorded its share of BPLP’s IFRS transition adjustments. BPLP’s transition adjustments relate largely to the recognition of previously unrecognized actuarial losses, as well as adjustments for changes in amounts eligible for capitalization, componentization of property, plant and equipment and the recognition of additional provisions as required under IFRS.

(i) BPLP’s policy choice under IFRS for defined benefit plans is to recognize all actuarial gains and losses in other comprehensive income. As a result of this policy choice, for all defined benefit plans existing at January 1, 2010, BPLP has recognized in retained earnings all cumulative actuarial losses. Cameco’s share of this adjustment was a decrease to retained earnings of $136,954,000. In addition, $144,760,000 of actuarial losses at December 31, 2010 was recognized directly in other comprehensive income following BPLP’s annual actuarial valuation update.

In 2005, BPLP sublet the four Bruce A reactors to a newly-formed partnership (the Bruce A Limited Partnership or “BALP”). BPLP continues to be responsible for the overall management of the site, including employment of the full workforce. BPLP and BALP entered into a services and cost sharing agreement to achieve an equitable allocation of certain operating costs, including employee pension and other post-retirement costs.

As a result of being the employer of record, BPLP has legal liability for the pension and other post-retirement benefit plans and is required to recognize the entire amount of any actuarial gains and losses in other comprehensive income. These costs are shared with BALP through the services and cost sharing agreement with amounts recovered from BALP classified in earnings rather than other comprehensive income.

(ii) Unlike Canadian GAAP, IFRS requires the cost of major inspections and overhauls to be recognized in the carrying amount of property, plant and equipment. It also requires that components of an item of property, plant and equipment with different useful lives be accounted for and depreciated separately. As a result of these different capitalization standards under IFRS, BPLP has made adjustments to retained earnings at its transition date. Cameco’s share of these adjustments was an increase to retained earnings of $8,469,000.

(iii) Under IFRS, unlike Canadian GAAP, provisions are required to be made when a constructive obligation exists. IFRS also varies from Canadian GAAP in its requirements for certain accruals to be made. Based on the differing requirements for the recognition of provisions and accruals, BPLP recorded a reduction to retained earnings of which Cameco’s share was $6,984,000.

The effect of the IFRS transition adjustments was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Accounts receivable (iii)	$	1,864		$	1,075
Long-term receivables, investments and other (i)		(60,482	)		(92,526	)
Property, plant and equipment (ii)		8,469			8,406
Accounts payable and accrued liabilities (iii)		(474	)		(2,781	)
Provisions (iii)		(4,519	)		(3,792	)
Other liabilities (i),(iii)		(80,327	)		(184,449	)
Retained earnings (i),(ii),(iii)		135,469			274,067
Consolidated Statements of Earnings and Consolidated Statements of Comprehensive Income
Products and services sold (i),(ii),(iii)	$	—		$	(14,125	)
Depreciation and amortization (ii)		—			7,963
Actuarial losses (i)		—			144,760

22

b) Under IFRS, and similar to Canadian GAAP, changes to a decommissioning liability to recognize the passage of time (unwinding of the discount or accretion) are required to be recorded. Under Canadian GAAP, the accretion was recorded as an operating cost and allocated to inventory while under IFRS, the unwinding of the discount is required to be reflected as a finance cost and does not qualify for capitalization. The effect was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Inventories	$	(8,387	)	$	(9,748	)
Property, plant and equipment		—			(75	)
Provisions		—			4,209
Retained earnings		8,387			5,658
Other components of equity (foreign currency translation)		—			(44	)
Consolidated Statements of Earnings
Depreciation and amortization	$	—		$	(15,516	)
Finance costs		—			12,787

c) Cameco has elected, under IFRS 1, not to apply IAS 23 retrospectively to borrowing costs incurred on the construction of qualifying assets that commenced prior to January 1, 2010. Accordingly, Cameco has derecognized all borrowing costs that had been previously capitalized under Canadian GAAP through a charge to retained earnings. In addition, based on this election, borrowing costs incurred subsequent to the date of transition on qualifying assets where the construction of the asset commenced prior to January 1, 2010 are being expensed as incurred. The effect was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Property, plant and equipment	$	(333,810	)	$	(377,182	)
Retained earnings		333,810			377,182
Consolidated Statements of Earnings
Depreciation and amortization	$	—		$	(4,349	)
Finance costs		—			47,721

d) IFRS requires the reversal of any previously recorded impairment losses where circumstances have changed such that the impairments have been reduced. The reversal of impairment losses was prohibited under Canadian GAAP. In 2000, as a result of depressed uranium prices, Cameco recorded a write-down relating to certain in situ recovery mine assets located in the United States. The amount of the write-down was determined based on estimated future net cash flows and uranium price forecasts. As a result of the strengthening of uranium prices since 2000, Cameco reassessed these previously impaired assets and based on their value in use, using a discount rate of 8.6%, determined that a portion of these previous write-downs should be reversed. The reversal of these impairment losses has been recognized in cost of sales in the statements of earnings and the effect was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Property, plant and equipment	$	34,600		$	31,540
Inventory		—			312
Retained earnings		(34,600	)		(33,497	)
Other components of equity (foreign currency translation)		—			1,645
Consolidated Statements of Earnings
Depreciation and amortization	$	—		$	1,103

23

e) IFRS specifically precludes the inclusion of general overhead and administration expenses in the cost of an item of property, plant and equipment. Cameco reviewed the composition of its items of property, plant and equipment to assess whether the costs included related specifically to the construction of the asset, or whether they were general in nature and determined that certain costs should be expensed under IFRS. The effect of removing these costs from property, plant and equipment was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Property, plant and equipment	$	(7,526	)	$	(7,072	)
Retained earnings		7,526			7,072
Consolidated Statements of Earnings
Depreciation and amortization	$	—		$	(454	)

f) Under IFRS, investments in equity-accounted investees are presented in the consolidated statements of financial position as a separate line item. Previously under Canadian GAAP, these investments were included in long-term receivables, investments and other. The effect of this reclassification was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Investments in equity-accounted investees	$	203,873		$	191,738
Long-term receivables, investments and other		(203,873	)		(191,738	)

g) Cameco’s policy choice under IFRS for defined benefit plans is to recognize all actuarial gains and losses in other comprehensive income. As a result of this policy choice, for all defined benefit plans existing at January 1, 2010, the Company has recognized in retained earnings, $14,404,000 of cumulative actuarial losses. The effect was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Long-term receivables, investments and other	$	(2,155	)	$	(1,885	)
Other liabilities		(12,249	)		(11,981	)
Retained earnings		14,404			13,753
Other components of equity (foreign currency translation)		—			113
Consolidated Statements of Earnings and Consolidated Statements of Comprehensive Income
Administration	$	—		$	(1,063	)
Actuarial losses		—			412

24

h) Under IFRS, in-process research and development (“IPR&D”) acquired in a business combination that meets the definition of an intangible asset is capitalized with amortization commencing when the asset is ready for use (i.e., when development is complete). Under Canadian GAAP, amortization of IPR&D capitalized as an intangible asset was commenced immediately, with the amortization period extending from the date of initial recognition to the date the completed asset will be available for use in commercial production. Cameco had been amortizing IPR&D related to the acquisition of its interest in equity-accounted investee GE-Hitachi Global Laser Enrichment LLC, a development-stage entity. Under IFRS, this amortization does not begin until development is complete. The effect of reversing this previously recognized amortization was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Investments in equity-accounted investees	$	18,691		$	28,692
Retained earnings		(18,691	)		(30,053	)
Other components of equity (foreign currency translation)		—			1,361
Consolidated Statements of Earnings
Share of loss from equity-accounted investees	$	—		$	(11,362	)

i) Cameco has granted cash-settled phantom stock options to eligible non-North American employees. The Company applied IFRS 2 to its unsettled share-based compensation arrangements at January 1, 2010.

Cameco accounted for these share-based compensation arrangements at intrinsic value under Canadian GAAP. The related liability has been adjusted to reflect the fair value of the outstanding cash-settled phantom stock options to be consistent with the Company’s accounting policies under IFRS. The effect of accounting for cash-settled share-based compensation transactions at fair value was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Accounts payable and accrued liabilities	$	(831	)	$	(782	)
Retained earnings		831			782
Consolidated Statements of Earnings
Administration	$	—		$	(49	)

j) Under IFRS, decommissioning liabilities and waste provisions are presented in the consolidated statements of financial position as part of provisions. Previously under Canadian GAAP, these obligations were presented separately as provision for reclamation and other liabilities. The effect of this reclassification was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Provision for reclamation	$	258,277		$	279,653
Provisions		(296,895	)		(317,313	)
Other liabilities		38,618			37,660

k) Cameco has elected, under IFRS 1, not to retrospectively recalculate, under IFRIC 1, the effect of each change in its reclamation provision prior to January 1, 2010. Instead, the liability and related assets and depreciation were measured as at the date of transition. Accordingly, Cameco has recalculated the provision and estimated the amount that would have been adjusted to the cost of the related asset by discounting the liability at the date of transition back to the date when the liability first arose, using its best estimate of the historical risk free rate that would have applied over the intervening period. In addition, the Company has calculated the accumulated depreciation on that amount as at the date of transition to IFRS based on the current estimate of the useful life of the asset.

In addition, as a result of its annual review, Cameco adjusted the provision for decommissioning liabilities and cost of the related assets for changes in discount rates which ranged from 4.1% - 4.6% at January 1, 2010 compared to 3.3% - 3.5% at December 31, 2010.

25

The effect of the IFRS transition adjustments was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Property, plant and equipment	$	(53,062	)	$	(38,779	)
Provisions		(57,188	)		(68,332	)
Retained earnings		110,250			108,262
Other components of equity (foreign currency translation)		—			(1,151	)
Consolidated Statements of Earnings
Depreciation and amortization	$	—		$	(1,988	)

l) IFRS requires that provisions such as those for environmental costs be recognized when it is probable that a restoration expense will be incurred and the associated costs can be reliably estimated. Where the liability will not be settled for a number of years, the amount recognized is the present value of the estimated future expenditure. Under IFRS, provisions for waste removal are measured initially at their present value using risk adjusted cash flows, with changes to the liability due to the passage of time (accretion) recorded as a finance cost. Under Canadian GAAP, discounting to reflect the time value of money is allowed, but not required. In the fuel services conversion processes, a certain amount of waste material is generated. Under Canadian GAAP, provisions for waste removal were measured using undiscounted estimated cash flows and recognized as an expense and a corresponding liability. The effect of discounting the provision upon transition to IFRS was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Provisions	$	1,773		$	261
Retained earnings		(1,773	)		(261	)
Consolidated Statements of Earnings
Products and services sold	$	—		$	209
Finance costs		—			1,303

m) Under IFRS, convertible debentures that contain a cash settlement feature are accounted for as a hybrid instrument with a debt component and a separate derivative representing the conversion option. The debt component is classified as a financial liability and accounted for at amortized cost using the effective interest rate method, while the conversion option is accounted for as a derivative and recorded at fair value with changes in fair value recorded in earnings.

Under Canadian GAAP, certain convertible debentures that contained a cash settlement feature were accounted for as a compound instrument with both a debt and equity component. Consistent with IFRS, the debt component was accounted for at amortized cost using the effective interest rate method; however, the conversion option was accounted for as an equity instrument with any changes in value not recognized.

The effect of accounting for the conversion option as a derivative at fair value was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Retained earnings	$	297,400		$	297,400
Share capital		(297,400	)		(297,400	)

n) In accordance with IFRS 1, Cameco has elected to deem all foreign currency translation differences recorded in other comprehensive income at the date of transition to IFRS in respect of all foreign entities to be zero at the date of transition.

The effect was to increase foreign currency translation (other components of equity) and to decrease retained earnings by $50,398,000 at January 1, 2010 and December 31, 2010.

26

In addition to the above, cash flow hedging reserves of $89,457,000 as at January 1, 2010 and $30,306,000 as at December 31, 2010 and available-for-sale assets reserves of $2,225,000 at January 1, 2010 and $1,793 at December 31, 2010 have been reclassified from accumulated other comprehensive income under Canadian GAAP to their respective reserve accounts within other components of equity under IFRS.

o) Under IFRS, non-controlling interests are presented in the consolidated statement of financial position as equity but are presented separately from the parent shareholders’ equity. Under Canadian GAAP, non-controlling interests were classified between total liabilities and equity and referred to as minority interest.

p) The foregoing changes decreased (increased) the deferred tax amounts as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
BPLP transition adjustments (a)	$	33,862		$	68,512
Decommissioning liabilities - discounting (k)		31,076			30,237
Decommissioning liabilities - accretion (b)		2,537			1,082
Provision for waste (l)		(468	)		(69	)
Borrowing costs (c)		88,159			99,609
Impairment reversal (d)		(12,125	)		(11,522	)
Capitalized overhead (e)		1,988			1,868
IPR&D (h)		(6,542	)		(10,042	)
Share-based compensation (i)		136			146
Employee benefits (g)		3,895			3,753
	$	142,518		$	183,574

In addition, other components of equity of $(794,000) as at December 31, 2010 have been adjusted to reflect the impact of foreign currency translation on the deferred tax balance.

The adjustments described above impacted income tax expense (recovery) on the consolidated statements of earnings as follows:

Consolidated Statements of Earnings	Jan 1/10		2010
BPLP transition adjustments (a)		—	$	1,540
Decommissioning liabilities - discounting (k)		—		436
Decommissioning liabilities - accretion (b)		—		1,427
Provision for waste (l)		—		(399	)
Borrowing costs (c)		—		(11,450	)
Capitalized overhead (e)		—		120
IPR&D (h)		—		3,977
Share-based compensation (i)		—		(10	)
Employee benefits (g)		—		287
Income tax recovery	$	—	$	(4,072	)

The adjustment to other comprehensive income relating to previously unrecognized cumulative actuarial losses in BPLP is net of taxes of $36,190,000.

27

q) Under IFRS, a deferred tax liability (asset) is recognized for the difference in tax bases between jurisdictions as a result of an intra-group transfer of assets and consequently, the deferred tax is computed using the tax rate applicable to the purchaser. Under Canadian GAAP, a deferred tax liability (asset) was not recognized for the difference in tax bases between jurisdictions. Any taxes paid or recovered by the transferor were recognized as an asset or liability once the profit or loss was recognized by the consolidated entity. The IFRS adjustment is related to product sold by Cameco to subsidiaries and held in inventory at the transition date. The effect was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Deferred tax liabilities	$	(540	)	$	19,690
Retained earnings		540			(19,690	)
Consolidated Statements of Earnings
Income tax recovery	$	—		$	(20,230	)

r) Under IFRS, a deferred tax liability (asset) is recognized for exchange gains and losses related to foreign non-monetary assets and liabilities that are remeasured into the functional currency using historical exchange rates for tax purposes. Under Canadian GAAP, a deferred tax liability (asset) is not recognized for a temporary difference between the historical exchange rate and the current exchange rate translations of non-monetary assets and liabilities. The effect was as follows:

Consolidated Statements of Financial Position	Jan 1/10			2010
Deferred tax liabilities	$	(4,133	)	$	(4,388	)
Retained earnings		4,133			4,612
Other components of equity (foreign currency translation)		—			(224	)
Consolidated Statements of Earnings
Income tax expense	$	—		$	479

s) The above changes increased (decreased) retained earnings as follows:

	Jan 1/10			2010
BPLP transition adjustments (a)	$	(135,469	)	$	(274,067	)
Decommissioning liabilities - accretion (b)		(8,387	)		(5,658	)
Borrowing costs (c)		(333,810	)		(377,182	)
Impairment reversal (d)		34,600			33,497
Capitalized overhead (e)		(7,526	)		(7,072	)
Employee benefits (g)		(14,404	)		(13,753	)
In-process research and development (h)		18,691			30,053
Share-based compensation (i)		(831	)		(782	)
Decommissioning liabilities - discounting (k)		(110,250	)		(108,262	)
Provision for waste - discounting (l)		1,773			261
Convertible debentures (m)		(297,400	)		(297,400	)
Other components of equity (n)		(50,398	)		(50,398	)
Deferred tax liability (p)		142,518			182,780
Deferred tax liabilities - intra-group transfer (q)		(540	)		19,690
Deferred tax liabilities - foreign non-monetary assets (r)		(4,133	)		(4,612	)
	$	(765,566	)	$	(872,905	)

28

Explanation of material adjustments to the cash flow statement for 2010

Consistent with the Company’s accounting policy election under IAS 7, Statement of Cash Flows, interest paid has been reclassified as a financing activity. Under Canadian GAAP, it had been included as part of investing activities. The amount reclassified was $53,859,000 for the year ended December 31, 2010.

There are no other material differences between the cash flow statement presented under IFRS and the cash flow statement presented under Canadian GAAP.

4. Accounting Standards

(a) 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, 2011, 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, 2013:

(i) Financial Instruments

In October 2010, the IASB issued IFRS 9, Financial Instruments (“IFRS 9”). This standard is effective for periods beginning on or after January 1, 2015 and is part of a wider project to replace IAS 39, Financial Instruments: Recognition and Measurement. IFRS 9 replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The basis of classification depends on the entity’s business model and the contractual cash flow characteristics of the financial asset or liability. The guidance in IAS 39 on impairment of financial assets and hedge accounting continues to apply. Cameco is assessing the impact of this new standard on its financial statements.

(ii) Consolidated Financial Statements

In May 2011, the IASB issued IFRS 10, Consolidated Financial Statements (“IFRS 10”). This standard is effective for periods beginning on or after January 1, 2013 and establishes principles for the presentation and preparation of consolidated financial statements when an entity controls one or more other entities. IFRS 10 defines the principle of control and establishes control as the basis for determining which entities are consolidated in the consolidated financial statements. Cameco is assessing the impact of this new standard on its financial statements.

(iii) Joint Arrangements

In May 2011, the IASB issued IFRS 11, Joint Arrangements (“IFRS 11”). This standard is effective for periods beginning on or after January 1, 2013 and establishes principles for financial reporting by parties to a joint arrangement. IFRS 11 requires a party to assess the rights and obligations arising from an arrangement in determining whether an arrangement is either a joint venture or a joint operation. Joint ventures are to be accounted for using the equity method while joint operations will continue to be accounted for using proportionate consolidation. Cameco is assessing the impact of this new standard on its financial statements.

(iv) Disclosure of Interests in Other Entities

In May 2011, the IASB issued IFRS 12, Disclosure of Interests in Other Entities (“IFRS 12”). This standard is effective for periods beginning on or after January 1, 2013 and applies to entities that have an interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. IFRS 12 integrates and makes consistent the disclosure requirements for a reporting entity’s interest in other entities and presents those requirements in a single standard. Cameco is assessing the impact of this new standard on its financial statements.

(v) Fair Value Measurement

In May 2011, the IASB issued IFRS 13, Fair Value Measurement (“IFRS 13”). This standard is effective for periods beginning on or after January 1, 2013 and provides additional guidance where IFRS requires fair value to be used. IFRS 13 defines fair value, sets out in a single standard a framework for measuring fair value and establishes the required disclosures about fair value measurements. Cameco is assessing the impact of this new standard on its financial statements.

(vi) Employee Benefits

In June 2011, the IASB issued an amended version of IAS 19, Employee Benefits (“IAS 19”). This amendment is effective for periods beginning on or after January 1, 2013 and eliminates the ‘corridor method’ of accounting for defined benefit plans. Revised IAS 19 also streamlines the presentation of changes in assets and liabilities arising from defined benefit plans, and enhances the disclosure requirements for defined benefit plans. Cameco is assessing the impact of this revised standard on its financial statements.

29

(vii) Presentation of Other Comprehensive Income

In June 2011, the IASB issued an amended version of IAS 1, Presentation of Financial Statements (“IAS 1”). This amendment is effective for periods beginning on or after January 1, 2012 and requires companies preparing financial statements in accordance with IFRS to group together items within OCI that may be reclassified to the profit or loss section of the statement of earnings. Revised IAS 1 also reaffirms existing requirements that items in OCI and profit or loss should be presented as either a single statement or two consecutive statements. Cameco is assessing the impact of this revised standard on its financial statements.

5. Determination of Fair Values

A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes to the specific asset or liability.

(a) Investments in Equity and Debt Securities

The fair value of available-for-sale financial assets is determined by reference to their quoted closing bid price at the reporting date. The fair value of unlisted securities is based on cash flows discounted using a rate based on the market interest rate and the risk premium specific to the unlisted securities.

(b) Derivatives

The fair value of forward exchange contracts is based on the current quoted foreign exchange rates. The fair value of interest rate swaps is determined by discounting estimated future cash flows based on the terms and maturity of each contract and using market interest rates for a similar instrument at the measurement date. The fair value of interest rate caps is based on broker quotes.

Fair values reflect the credit risk of the instrument and include adjustments to take into account the credit risk of the Company and counterparty when appropriate.

(c) Share-Based Compensation

The fair values of the stock option, phantom stock option, deferred share unit and restricted share unit plans are measured using the Black-Scholes option-pricing model. The fair value of the performance share unit plan is measured using Monte Carlo simulation. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility), weighted average expected life of the instruments (based on historical experience and general option holder behavior), expected dividends and the risk-free interest rate (based on government bonds). Service and non-market performance conditions attached to the transactions are taken into account in determining fair value for valuations performed using Monte Carlo simulation.

6. 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, income 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 estimates and assumptions may be found in the relevant notes to the 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 future prices, costs of production, sustaining capital requirements and mineral reserves. A material change in assumptions may significantly impact the potential impairment of these assets. In addition, assumptions used in the calculation of recoverable amounts are discount rates, future cash flows and profit margins.

30

(b) 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.

(c) 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 financial statements. In calculating the 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 results. Cameco estimates deferred income taxes based on temporary differences between the income and losses reported in its 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 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.

(d) 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 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 and depletion charged to earnings.

(e) 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 would result in a material impact to the financial statements.

7. Short-Term Investments

Short-term investments are denominated in Canadian dollars and are comprised of money market instruments with terms to maturity between three and 12 months. Short-term investments are classified as available-for-sale.

8. Accounts Receivable

	2011		2010		Jan 1/10
Trade receivables	$	564,994	$	401,727	$	404,574
Receivables due from related parties [note 37]		19,557		22,226		15,137
HST/VAT receivables		16,675		15,093		16,803
Other receivables		10,955		9,433		12,072
Total	$	612,181	$	448,479	$	448,586

The Company’s exposure to credit and currency risks as well as impairment loss related to trade and other receivables, excluding HST/VAT receivables is disclosed in note 29.

31

9. Inventories

	2011		2010		Jan 1/10
Uranium
Concentrate	$	361,481	$	385,242	$	304,695
Broken ore		14,310		12,138		18,077
		375,791		397,380		322,772
Fuel Services		118,084		135,710		122,065
Total	$	493,875	$	533,090	$	444,837

10. Property, Plant and Equipment

	Land and buildings			Plant and equipment (a)			Furniture and fixtures			Under construction			Exploration and evaluation		Total
Cost
At January 1, 2010	$	2,020,866		$	2,119,054		$	79,324		$	1,037,777		$	538,351	$	5,795,372
Additions		75,846			15,547			1,578			368,805			—		461,776
Transfers		117,376			90,166			4,828			(212,370	)		—		—
Disposals		(154	)		(6,894	)		(65	)		—			—		(7,113	)
Effect of movements in exchange rates		(26,987	)		(5,379	)		(327	)		(4,358	)		44,982		7,931
At December 31, 2010		2,186,947			2,212,494			85,338			1,189,854			583,333		6,257,966
Accumulated depreciation
At January 1, 2010		987,724			1,041,612			49,262			—			—		2,078,598
Depreciation charge		98,645			125,359			13,776			—			—		237,780
Transfers		3,501			(4,128	)		627			—			—		—
Disposals		(39	)		(5,503	)		(27	)		—			—		(5,569	)
Effect of movements in exchange rates		(6,190	)		(1,159	)		(141	)		—			—		(7,490	)
At December 31, 2010		1,083,641			1,156,181			63,497			—			—		2,303,319
Net book value at December 31, 2010	$	1,103,306		$	1,056,313		$	21,841		$	1,189,854		$	583,333	$	3,954,647
Net book value at January 1, 2010	$	1,033,142		$	1,077,442		$	30,062		$	1,037,777		$	538,351	$	3,716,774

32

	Land and buildings			Plant and equipment (a)			Furniture and fixtures			Under construction			Exploration and evaluation		Total
Cost
At January 1, 2011	$	2,186,947		$	2,212,494		$	85,338		$	1,189,854		$	583,333	$	6,257,966
Additions		196,596			33,373			3,263			579,018			—		812,250
Transfers		75,976			131,306			3,762			(211,044	)		—		—
Disposals		(4,226	)		(33,949	)		(12	)		(3,083	)		—		(41,270	)
Effect of movements in exchange rates		8,454			3,364			212			2,324			13,981		28,335
At December 31, 2011		2,463,747			2,346,588			92,563			1,557,069			597,314		7,057,281
Accumulated depreciation
At January 1, 2011		1,083,641			1,156,181			63,497			—			—		2,303,319
Depreciation charge		106,241			131,983			12,007			—			—		250,231
Disposals		(3,597	)		(29,998	)		(11	)		—			—		(33,606	)
Effect of movements in exchange rates		4,115			985			130			—			—		5,230
At December 31, 2011		1,190,400			1,259,151			75,623			—			—		2,525,174
Net book value at December 31, 2011	$	1,273,347		$	1,087,437		$	16,940		$	1,557,069		$	597,314	$	4,532,107

^(a)  At December 31, 2011, the net amount included in the statement of financial position for plant and equipment includes Cameco’s share of BPLP’s nuclear generating plant under finance lease of $93,220,000.

On February 7, 2011, Cameco signed two agreements with Talvivaara Mining Company Plc. to buy uranium produced at the Sotkamo nickel-zinc mine in Finland. Under the first agreement with Talvivaara, Cameco will provide an up-front payment, to a maximum of $60,000,000 (US) to cover certain construction costs. This amount will be repaid through deliveries of uranium concentrate. Once the full amount has been repaid, Cameco will continue to purchase the uranium concentrates produced at the Sotkamo mine through a second agreement which provides for the purchase of uranium using a pricing formula that references market prices at the time of delivery. The second agreement expires on December 31, 2027.

11. Intangible Assets

	Intellectual Property		Patents		Total
Cost
At January 1, 2010	$	118,819	$	—	$	118,819
Additions		—		—		—
At December 31, 2010		118,819		—		118,819
Accumulated depreciation
At January 1, 2010		21,106		—		21,106
Amortization charge		3,443		—		3,443
At December 31, 2010		24,549		—		24,549
Net book value at December 31, 2010	$	94,270	$	—	$	94,270
Net book value at January 1, 2010	$	97,713	$	—	$	97,713

33

	Intellectual Property		Patents		Total
Cost
At January 1, 2011	$	118,819	$	—	$	118,819
Additions		—		8,462		8,462
Effect of movements in exchange rates		—		428		428
At December 31, 2011		118,819		8,890		127,709
Accumulated depreciation
At January 1, 2011		24,549		—		24,549
Amortization charge		3,960		239		4,199
Effect of movements in exchange rates		—		7		7
At December 31, 2011		28,509		246		28,755
Net book value at December 31, 2011	$	90,310	$	8,644	$	98,954

The intangible asset values relate to intellectual property acquired with Cameco Fuel Manufacturing (“CFM”) and patents acquired with UFP Investments LLC (“UFP”). The CFM intellectual property is being amortized on a unit-of-production basis over its remaining life which expires in 2030. 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.

12. Long-Term Receivables, Investments and Other

	2011			2010			Jan 1/10
BPLP
Finance lease receivable from BALP (a)	$	87,785		$	91,608		$	94,895
Derivatives [note 29]		54,010			77,831			141,949
Available-for-sale securities
Western Uranium Corporation		—			6,033			4,637
GoviEx Uranium		21,057			23,017			25,214
Derivatives [note 29]		17,392			50,011			68,432
Deferred charges
Cost of sales		—			—			14,415
Advances receivable from JV Inkai LLP [note 37]		78,058			125,072			141,149
Other		87,949			60,550			64,810
		346,251			434,122			555,501
Less current portion		(62,433	)		(95,271	)		(158,011	)
Net	$	283,818		$	338,851		$	397,490

^(a)  BPLP leases the Bruce A nuclear generating plants and other property, plant and equipment to BALP under a sublease agreement. Future minimum base rent sublease payments under the capital lease receivable are imputed using a 7.5% discount rate. The future minimum lease payments are as follows:

34

As at December 31, 2011
	Future minimum lease payments		Interest		Present value of minimum lease payments
Less than one year	$	12,640	$	6,372	$	6,268
Between one and five years		59,800		19,566		40,234
More than five years		44,550		3,267		41,283
Total	$	116,990	$	29,205	$	87,785
As at December 31, 2010
	Future minimum lease payments		Interest		Present value of minimum lease payments
Less than one year	$	9,684	$	6,191	$	3,493
Between one and five years		53,901		22,232		31,669
More than five years		63,970		7,524		56,446
Total	$	127,555	$	35,947	$	91,608

Included in finance income is $6,741,000 related to the finance lease receivable for the year ended December 31, 2011 (2010 - $6,952,000).

The lease agreement includes supplemental lease payments which are classified as contingent rents. Annual supplemental rents of $30,000,000 (subject to CPI) per operating reactor are payable by BPLP to Ontario Power Generation Inc. (“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.

BPLP leases the Bruce A nuclear generating plants and other property, plant and equipment to BALP under a sublease agreement. In accordance with the Sublease Agreement, BALP will participate in its share of supplemental rent and any subsequent adjustments. There were $58,460,000 in supplemental lease payments to OPG recognized in 2011 (2010 - $54,352,000). Of this amount, $19,276,000 was reimbursed to BPLP from BALP during 2011 (2010 - $18,960,000). The net amounts have been recognized in cost of products and services sold.

Additionally, the base rent payments during the renewal periods have been classified as contingent rents. The calculation of the renewal base rent payments is based on the proportion of operational BALP units versus BPLP units, contingent on the extent of use of the respective stations. These base rents will commence in 2019.

13. Equity-Accounted Investees

	2011			2010
Beginning of year	$	220,430		$	222,564
Investment cost addition		10,026			13,582
Share of loss		(7,233	)		(4,176	)
Disposal of associate		—			(945	)
Control of associate acquired (note 36)		(6,846	)		—
Exchange differences and other		3,849			(10,595	)
End of year	$	220,226		$	220,430

35

Summary financial information for Cameco’s equity-accounted investees, adjusted for the percentage of ownership held, is as follows:

	2011			2010			Jan 1/10
Current assets	$	22,402		$	35,954		$	36,938
Non-current assets		51,129			44,667			30,482
Current liabilities		(3,669	)		(1,439	)		(1,687	)
Non-current liabilities		(3,114	)		(4,109	)		(3,142	)
Net Assets	$	66,748		$	75,073		$	62,591
Revenue	$	1,608		$	3,580		$	—
Expenses		(8,841	)		(7,756	)		—
Net Loss	$	(7,233	)	$	(4,176	)	$	—

At December 31, 2011, the quoted value of the Company’s share in associates having shares listed on recognized stock exchanges was $30,268,000 (December 31, 2010 - $103,186,000). The carrying value of these investments was $6,699,000 at December 31, 2011 (December 31, 2010 - $9,998,000).

While the Company has less than a 20% interest in UrAmerica Ltd., it is considered to have significant influence because it has the right to appoint a director to the board.

14. Accounts Payable and Accrued Liabilities

	2011		2010		Jan 1/10
Trade payables	$	312,751	$	263,147	$	378,539
Non-trade payables		134,614		97,232		98,266
Payables due to related parties [note 37]		9,942		29,580		17,276
Total	$	457,307	$	389,959	$	494,081

The Company’s exposure to currency and liquidity risk related to trade and other payables is disclosed in note 29.

15. Short-Term Debt

	2011		2010		Jan 1/10
Promissory note payable	$	73,059	$	72,948	$	76,762
BPLP		18,644		12,640		10,744
Total	$	91,703	$	85,588	$	87,506

In 2008, a promissory note in the amount of $73,344,000 (US) was issued to finance the acquisition of GE-Hitachi Global Laser Enrichment LLC (GLE). The promissory note is payable on demand and bears interest at a market rate of 2.27%. At December 31, 2011, $71,838,000 (US) (2010 - $73,344,000 (US)) was outstanding under this promissory note.

BPLP has a $150,000,000 working capital and operational letter of credit facility that is available until July 30, 2013, as well as $412,000,000 in letter of credit facilities. As at December 31, 2011, BPLP had $75,000,000 outstanding under the working capital ($59,000,000) and operational letter of credit facility ($16,000,000) (2010 - $45,000,000) and $362,000,000 outstanding under the letter of credit facilities (2010 - $270,000,000). Cameco’s share of the available facilities is $47,400,000 under the working capital and operational letter of credit facility and $130,190,000 in letter of credit facilities. As at December 31, 2011, Cameco’s share outstanding under the working capital ($18,644,000) and operational letter of credit facility ($5,056,000) was $23,700,000 (2010 - $14,220,000) and $114,390,000 under the letter of credit facilities (2010 - $85,320,000).

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16. Long-Term Debt

	2011		2010		Jan 1/10
Debentures - Series C	$	298,993	$	298,721	$	298,449
Debentures - Series D		496,152		495,762		495,393
JV Inkai LLP		6,126		—		—
Total	$	801,271	$	794,483	$	793,842

Cameco has $299,000,000 outstanding in senior unsecured debentures (Series C). These debentures bear interest at a rate of 4.70% per annum (effective interest rate of 4.79%) and mature on September 16, 2015.

On September 2, 2009, Cameco issued debentures (Series D) in the amount of $500,000,000. These debentures bear interest at a rate of 5.67% per annum (effective interest rate of 5.80%) and mature on September 2, 2019. The proceeds of the issue after deducting expenses were $495,300,000.

In February 2009, Cameco concluded an arrangement for a $100,000,000 unsecured revolving credit facility. The original maturity date of the facility was February 5, 2010, however, in November 2010, upon mutual agreement with the lender, this facility was further extended to February 4, 2012. On November 1, 2011, Cameco cancelled this facility.

On November 1, 2011, Cameco amended and extended the term of our $500,000,000 unsecured revolving credit facility that was maturing November 30, 2012. This credit facility was increased to $1,250,000,000 and now matures on November 1, 2016. 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 facility ranks equally with all of our other senior debt. As of December 31, 2011 there were no amounts outstanding under this facility. The agreement provides the ability to increase the revolving credit facility above $1,250,000,000 by no less than increments of $50,000,000, up to a total of $1,750,000,000.

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, 2011, Cameco was in compliance with the covenant and does not expect its operating and investing activities in 2012 to be constrained by it.

Cameco has $693,094,000 ($400,614,000 and $287,591,000 (US)) in letter of credit facilities. The majority of the outstanding letters of credit at December 31, 2011 relate to future decommissioning and reclamation liabilities [note 19] and amounted to $664,575,000 ($395,606,000 and $264,186,000 (US)) (2010 - $549,533,000 ($395,818,000 and $153,987,000 (US)).

Inkai has a $20,000,000 (US) revolving credit facility that is available until August 11, 2014. As at December 31, 2011, Inkai had $10,000,000 (US) outstanding under this facility. Cameco’s share of this facility and the amount outstanding under it is $12,000,000 (US) and $6,000,000 (US) respectively.

The table below represents currently scheduled maturities of long-term debt over the next five years.

2012	$	—
2013		—
2014		6,126
2015		298,993
2016		—
Thereafter		496,152
Total	$	801,271

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17. Finance Lease Obligation

BPLP holds a long-term lease with Ontario Power Generation Inc. (“OPG”) to operate the Bruce nuclear power facility. The initial term of the lease expires in 2018, with options to extend the lease for up to an additional 25 years. The interest rate associated with the lease is 7.5%. The future minimum lease payments are as follows:

As at December 31, 2011
	Future minimum lease payments		Interest		Present value of minimum lease payments
Less than one year	$	25,280	$	10,428	$	14,852
Between one and five years		106,492		28,728		77,764
More than five years		57,512		4,294		53,218
Total	$	189,284	$	43,450	$	145,834
As at December 31, 2010
	Future minimum lease payments		Interest		Present value of minimum lease payments
Less than one year	$	24,648	$	11,471	$	13,177
Between one and five years		103,964		34,230		69,734
More than five years		85,320		9,220		76,100
Total	$	213,932	$	54,921	$	159,011

Included in finance costs is $11,376,000 related to the finance lease obligation for the year ended December 31, 2011 (2010 - $12,324,000).

The lease agreement includes supplemental payments which are classified as contingent rents. Annual supplemental rents of $30,000,000 (subject to CPI) per operating reactor are payable by BPLP to Ontario Power Generation Inc. (“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.

BPLP leases the Bruce A nuclear generating plants and other property, plant and equipment to BALP under a sublease agreement. In accordance with the Sublease Agreement, BALP will participate in its share of supplemental rent and any subsequent adjustments. There were $58,460,000 in supplemental lease payments to OPG recognized in 2011 (2010 - $54,352,000). Of this amount, $19,276,000 was reimbursed to BPLP from BALP during 2011 (2010 - $18,960,000). The net amounts have been recognized in cost of products and services sold.

Additionally, the base rent payments during the renewal periods have been classified as contingent rents. The calculation of the renewal base rent payments is based on the proportion of operational BALP units versus BPLP units, contingent on the extent of use of the respective stations. These base rents will commence in 2019.

38

18. Other Liabilities

	2011			2010			Jan 1/10
Deferred sales	$	13,739		$	17,004		$	24,982
Derivatives [note 29]		28,499			5,273			4,137
Defined benefit liability [note 28]		38,050			21,738			19,141
BPLP
Defined benefit liability [note 28]		468,363			349,129			229,599
Derivatives [note 29]		19,439			29,954			36,820
OPG loan		4,045			—			—
Other		6,624			8,079			13,009
		578,759			431,177			327,688
Less current portion		(50,495	)		(28,228	)		(29,297	)
Total	$	528,264		$	402,949		$	298,391

19. Provisions

	Reclamation			Waste Disposal			Total
Balance at January 1, 2011	$	344,426		$	40,541		$	384,967
Provisions made during the period		167,957			6,891			174,848
Provisions used during the period		(18,498	)		(13,950	)		(32,448	)
Provisions reversed during the period		—			(8,927	)		(8,927	)
Unwinding of discount		12,266			1,161			13,427
Impact of foreign exchange		2,615			—			2,615
Balance at December 31, 2011	$	508,766		$	25,716		$	534,482
Current	$	9,979		$	4,878		$	14,857
Non-current		498,787			20,838			519,625
	$	508,766		$	25,716		$	534,482

(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 $576,976,170. The expected timing of these outflows is based on life of mine plans with the majority of expenditures expected to occur after 2017. 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 $664,214,040 in the form of letters of credit to satisfy current regulatory requirements.

The reclamation provision relates to the following segments:

	2011		2010
Uranium	$	381,967	$	262,159
Fuel Services		126,799		82,267
Total	$	508,766	$	344,426

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(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 $26,794,900. The expected timing of these outflows is expected to occur within the next 5 years.

20. Share Capital

Authorized share capital:

Unlimited number of first preferred shares

Unlimited number of second preferred shares

Unlimited number of voting common shares, and

One Class B share

(a) Common Shares

Number Issued (Number of Shares)	2011		2010
Beginning of year		394,351,043		392,838,733
Issued:
Stock option plan [note 27]		394,380		1,512,310
Issued share capital		394,745,423		394,351,043

(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, 2011, the dividend declared per share was $0.40 and $0.28 for the year ended December 31, 2010.

21. Employee Benefit Expense

The following employee benefit expenses are included in cost of products and services sold, administration, exploration, research and development, Cigar Lake remediation expenses and property, plant and equipment.

	2011			2010
Wages and salaries	$	513,830		$	465,317
Statutory and company benefits		84,235			80,994
Equity-settled share-based compensation		24,139			17,138
Expenses related to defined benefit plans		25,759			19,459
Contributions to defined contribution plans		16,663			13,921
Cash-settled share-based compensation		(10,333	)		2,902
Total	$	654,293		$	599,731

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22. Finance Costs

	2011			2010
Interest on long-term debt	$	57,143		$	56,338
Unwinding of discount on provisions		13,427			14,117
Other charges		3,179			8,609
Foreign exchange (gains) losses		(1,678	)		5,110
Interest on short-term debt		1,597			2,005
Total	$	73,668		$	86,179

23. Other Income

	2011		2010
Sale of investments	$	4,623	$	5,263
Other		297		(875	)
Total	$	4,920	$	4,388

24. Income Taxes

(a) Significant Components of Deferred Tax Assets and Liabilities

	Recognized in Earnings						As at December 31
	2011			2010			2011			2010
Assets
Provision for reclamation	$	47,645		$	4,030		$	159,455		$	110,261
Foreign exploration and development		432			4,053			9,683			9,251
Income tax losses		55,702			(196,241	)		67,072			11,370
Other		7,150			16,294			97,807			51,323
Deferred tax assets	$	110,929		$	(171,864	)	$	334,017		$	182,205
Liabilities
Property, plant and equipment	$	110,616		$	(186,169	)	$	243,345		$	134,278
Inventories		(3,301	)		(1,318	)		4,629			7,930
Long-term investments and other		(27,857	)		(7,589	)		12,816			40,673
Deferred tax liabilities	$	79,458		$	(195,076	)	$	260,790		$	182,881
Net deferred tax asset (liability)	$	31,471		$	23,212		$	73,227		$	(676	)
Deferred tax allocated as
Deferred tax assets							$	81,392		$	25,594
Deferred tax liabilities								(8,165	)		(26,270	)
Net deferred tax asset (liability)							$	73,227		$	(676	)

41

(b) Movement in Net Deferred Tax Assets and Liabilities

	2011			2010
Deferred tax liability at January 1	$	(676	)	$	(83,646	)
Expense for the year in net earnings		31,471			23,212
Expense for the year in other comprehensive income		38,951			62,826
Foreign exchange adjustments		3,481			(3,068	)
Deferred tax asset (liability) at December 31	$	73,227		$	(676	)

(c) Significant Components of Unrecognized Deferred Tax Assets

	2011		2010
Income tax losses	$	45,847	$	30,255
Property, plant and equipment		27,328		20,348
Long-term investments and other		2,893		13,240
Unrecognized deferred tax assets at December 31	$	76,068	$	63,843

(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:

	2011			2010
Earnings before income taxes and non-controlling interest	$	450,390		$	509,466
Combined federal and provincial tax rate		28.4	%		30.2	%
Computed income tax expense		127,911			153,859
Increase (decrease) in taxes resulting from:
Change in income tax rates		7,582			(29,508	)
Manufacturing and processing deduction		—			(3,846	)
Difference between Canadian rate and rates applicable to subsidiaries in other countries		(184,901	)		(143,347	)
Change in unrecorded deferred tax assets		15,961			13,499
Other provincial taxes		2,935			1,409
Share-based compensation plans		4,295			2,696
Change in tax provision related to transfer pricing		27,000			3,000
Other permanent differences		10,972			5,665
Income tax expense	$	11,755		$	3,427

(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 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, 2004, 2005 and 2006, which have increased Cameco’s income for Canadian income tax purposes by approximately $43,000,000, $108,000,000, $197,000,000 and $243,000,000 respectively. No reassessment received to date has resulted in more than a nominal amount of cash taxes becoming payable due to the availability of elective deductions and tax loss carrybacks. Cameco believes it is likely that CRA will reassess Cameco’s tax returns for subsequent years on a similar basis.

CRA’s Transfer Pricing Review Committee has not imposed a transfer pricing penalty for any year reassessed to date.

42

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. 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 the current period in the amount of $54,000,000. No provisions for penalties or interest have been recorded. Cameco does not expect more than a nominal amount of cash taxes to be payable due to the availability of elective deductions and tax loss carryovers. 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 over the period. However, an unfavourable outcome for the years 2003 to 2011 could be material to Cameco’s financial position, results of operations or 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 the Income Tax Act.

(f) Earnings and Income Taxes by Jurisdiction

	2011			2010
Earnings (loss) before income taxes
Canada	$	(376,952	)	$	(63,213	)
Foreign		827,342			572,679
	$	450,390		$	509,466
Current income taxes (recovery)
Canada	$	(7,856	)	$	(12,280	)
Foreign		51,082			38,919
	$	43,226		$	26,639
Deferred income taxes (recovery)
Canada	$	(47,427	)	$	(27,339	)
Foreign		15,956			4,127
	$	(31,471	)	$	(23,212	)
Income tax expense	$	11,755		$	3,427

(g) Income Tax Losses

At December 31, 2011, income tax losses carried forward of $402,041,000 (2010 - $136,242,000) are available to reduce taxable income. These losses expire as follows:

Date of expiry	Canada		US		Other		Total
2013		—	$	216		—	$	216
2019		—		—		3,057		3,057
2029		—		8,279		—		8,279
2030		410		10,783		—		11,193
2031		227,159		—		—		227,159
No expiry		—		—		152,137		152,137
	$	227,569	$	19,278	$	155,194	$	402,041

Included in the table above is $152,848,000 (2010 - $101,000,000) of temporary differences related to loss carry forwards where no future benefit is realized.

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(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, 2011
	Before tax			Income tax recovery (expense)			Net of tax
Exchange differences on translation of foreign operations	$	38,635		$	—		$	38,635
Gains on derivatives designated as cash flow hedges		10,717			(2,763	)		7,954
Gains on derivatives designated as cash flow hedges transferred to net earnings		(25,506	)		6,806			(18,700	)
Unrealized gains on assets available-for-sale		311			(39	)		272
Gains on assets available-for-sale transferred to net earnings		(2,209	)		292			(1,917	)
Defined benefit plan actuarial losses		(138,692	)		34,655			(104,037	)
	$	(116,744	)	$	38,951		$	(77,793	)
For the year ended December 31, 2010
	Before tax			Income tax recovery (expense)			Net of tax
Exchange differences on translation of foreign operations	$	6,435		$	—		$	6,435
Gains on derivatives designated as cash flow hedges		15,012			(2,977	)		12,035
Gains on derivatives designated as cash flow hedges transferred to net earnings		(100,586	)		29,400			(71,186	)
Unrealized gains on assets available-for-sale		2,455			(330	)		2,125
Gains on assets available-for-sale transferred to net earnings		(2,956	)		399			(2,557	)
Defined benefit plan actuarial losses		(145,316	)		36,334			(108,982	)
	$	(224,956	)	$	62,826		$	(162,130	)

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25. 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 2011 was 394,661,591 (2010 – 393,168,523).

	2011		2010
Basic earnings per share computation
Net earnings attributable to equity holders	$	450,404	$	516,391
Weighted average common shares outstanding		394,662		393,169
Basic earnings per common share	$	1.14	$	1.31
Diluted earnings per share computation
Net earnings attributable to equity holders	$	450,404	$	516,391
Weighted average common shares outstanding		394,662		393,169
Dilutive effect of stock options		817		1,850
Weighted average common shares outstanding, assuming dilution		395,479		395,019
Diluted earnings per common share	$	1.14	$	1.31

26. Statements of Cash Flows

Other Operating Items

	2011			2010
Changes in non-cash working capital:
Accounts receivable	$	(158,779	)	$	8,509
Inventories		29,105			(73,524	)
Supplies and prepaid expenses		8,094			(21,229	)
Accounts payable and accrued liabilities		68,369			(123,634	)
Other		(64,656	)		(59,176	)
Total	$	(117,867	)	$	(269,054	)

27. 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 officers and other employees of Cameco. Options granted under the stock option plan have an exercise price of not less than 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. Options have not been awarded to directors since 2003 and the plan has been amended to preclude the issue of options to directors.

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 26,486,819 shares have been issued.

45

Stock option transactions for the respective years were as follows:

(Number of Options)	2011			2010
Beginning of period		7,552,379			7,939,833
Options granted		1,630,069			1,515,945
Options forfeited		(261,978	)		(391,089	)
Options exercised [note 20]		(394,380	)		(1,512,310	)
End of period		8,526,090			7,552,379
Exercisable		5,556,417			4,814,761

Weighted average exercise prices were as follows

	2011		2010
Beginning of period	$	30.26	$	27.42
Options granted		39.10		28.90
Options forfeited		36.88		35.05
Options exercised		14.68		12.75
End of period	$	32.47	$	30.26
Exercisable	$	32.16	$	32.02

Total options outstanding and exercisable at December 31, 2011 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
$10.50 - 26.24		1,733,874		4.5	$	16.83		1,269,076	$	15.66
26.25 - 55.00		6,792,216		3.5		36.46		4,287,341		37.04
		8,526,090						5,556,417

The foregoing options have expiry dates ranging from March 9, 2012 to March 2, 2019

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

(Number of Options)	2011			2010
Beginning of period		2,737,618			2,389,685
Options granted		1,630,069			1,515,945
Options forfeited		(96,055	)		(91,439	)
Options vested		(1,301,959	)		(1,076,573	)
End of period		2,969,673			2,737,618

For the year ended December 31, 2011, Cameco has recorded a net expense of $14,803,000 (2010 - $8,931,000), related to options that vested during the year.

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(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.

Cameco records compensation expense with an offsetting credit to contributed surplus to reflect the estimated fair value of PSUs granted to employees. For the year ended December 31, 2011, the amount recorded was $4,392,000 (2010 - $3,679,000). As of December 31, 2011, the total PSUs held by the participants after adjusting for forfeitures on retirement was 310,413 (2010 - 395,360).

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.

Cameco records compensation expense with an offsetting credit to contributed surplus to reflect the estimated fair value of RSUs granted to employees. For the year ended December 31, 2011, the amount recorded was $297,000 (2010 - nil). As of December 31, 2011, the total RSU’s held by the participants was 70,000 (2010 – nil).

The Company has the following cash-settled plans:

a) Deferred Share Unit (DSU)

Cameco offers a deferred share unit 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, 2011, the total DSUs held by participating directors was 380,851 (2010 – 354,276).

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, 2011, the number of options held by participating employees was 249,227 (2010 - 242,051) with exercise prices ranging from $10.51 to $46.88 per share (2010 - $5.88 to $46.88) and a weighted average exercise price of $31.48 (2010 - $29.97).

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

47

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			RSUs
Number of options granted		1,630,069			146,450			70,000
Average strike price	$	39.10			—			—
Expected dividend	$	0.40		$	0.00		$	0.40
Expected volatility		39	%		50	%		39	%
Risk-free interest rate		2.5	%		2.2	%		2.5	%
Expected life of option		4.5 years			3 years			3 years
Expected forfeitures		15	%		0	%		0	%
Weighted average grant date fair values	$	12.57		$	42.11		$	25.44

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

	DSUs			Phantom Option Plan
Number of units outstanding		380,851			249,227
Average strike price		—		$	31.53
Expected dividend	$	0.40		$	0.40
Expected volatility		42	%		42	%
Risk-free interest rate		1.1	%		1.1	%
Expected life of option		3.5 years			3.5 years
Expected forfeitures		0	%		0	%
Weighted average measurement date fair values	$	18.41		$	2.17

Cameco also has an employee share ownership plan which commenced in 2007, 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 on January 1 of the second plan year following the date on which such shares were purchased. At December 31, 2011, there were 3,695 participants in the plan (2010 – 3,496). The total number of shares purchased in 2011 on behalf of participants, including the Company contribution, was 257,747 shares (2010 – 214,795). In 2011, the Company’s contributions totaled $4,647,000 (2010 - $4,528,000).

Cameco has recognized the following expenses (recoveries) under these plans:

	2011			2010
Deferred share units	$	(7,725	)	$	1,971
Phantom stock options		(2,608	)		931
Employee share ownership plan		4,647			6,608

At December 31, 2011, a liability of $7,479,000 (2010 - $17,581,000) was included in the statement of financial position to recognize accrued but unpaid expenses for these plans.

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28. Pension and Other Post-Retirement Benefits

Cameco maintains both defined benefit and defined contribution plans providing pension and post-retirement benefits to substantially all of its employees.

Under the defined pension benefit plans, Cameco provides benefits to retirees based on their length of service and final average earnings. The non-pension post-retirement plan covers such benefits as group life and supplemental health insurance to eligible employees and their dependants. The costs related to the non-pension post-retirement plans are charged to earnings in the period during which the employment services are rendered. However, these future obligations are not funded.

The effective date for the most recent valuations for funding purposes on the pension benefit plans is January 1, 2009. The next planned effective date for valuation for funding purposes of the pension benefit plans is set to be January 1, 2012.

A reconciliation of the funded status of the benefit plans to the financial statements is as follows:

	Pension Benefit Plans						Other Benefit Plans
	2011			2010			2011			2010
Fair value of plans assets, beginning of year	$	27,135		$	24,209		$	—		$	—
Expected return on assets		880			778			—			—
Actuarial gain (loss)		(562	)		2,961			—			—
Employer contributions		1,875			1,158			—			—
Benefits paid		(7,562	)		(1,971	)		—			—
Fair value of plan assets, end of year	$	21,766		$	27,135		$	—		$	—
Defined benefit obligation, beginning of year	$	35,518		$	30,840		$	13,355		$	12,019
Current service cost		1,283			1,330			727			880
Interest cost		1,948			1,905			747			1,057
Actuarial loss		12,934			3,535			1,803			—
Past service cost		—			—			688			—
Benefits paid		(7,562	)		(2,011	)		(1,044	)		(601	)
Foreign exchange		(10	)		(81	)		—			—
Defined benefit obligation, end of year	$	44,111		$	35,518		$	16,276		$	13,355
Funded status of plans - deficit	$	(22,345	)	$	(8,383	)	$	(16,276	)	$	(13,355	)
Unrecognized past service cost		—			—			571			—
Defined benefit liability [note 18]	$	(22,345	)	$	(8,383	)	$	(15,705	)	$	(13,355	)

The actual return on plan assets for the pension benefit plans for the year ended December 31, 2011 was $318,400 (2010 - $3,739,300).

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
	2011			2010
Asset Category (i)
Equity securities		22	%		26	%
Fixed income		20	%		22	%
Other (ii)		58	%		52	%
Total		100	%		100	%

⁽ⁱ⁾  The defined benefit plan assets contain no material amounts of related party assets at December 31, 2011 and 2010 respectively.

49

⁽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.

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

	Pension Benefit Plans						Other Benefit Plans
	2011			2010			2011		2010
Current service cost	$	1,283		$	1,330		$	727	$	880
Interest cost		1,948			1,905			747		1,057
Expected return on plan assets		(880	)		(778	)		—		—
Past service cost		—			—			117		—
Defined benefit pension expense		2,351			2,457			1,591		1,937
Defined contribution pension expense		16,663			13,921			—		—
Net pension and other benefit expense	$	19,014		$	16,378		$	1,591	$	1,937

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

	Pension Benefit Plans						Other Benefit Plans
	2011			2010			2011			2010
Discount rate		4.5	%		5.5	%		4.5	%		5.5	%
Rate of compensation increase		4.0	%		4.5	%		—			—
Long-term rate of return on assets		5.9	%		5.9	%		—			—
Health care cost trend rate		—			—			9.0	%		9.0	%

The long-term rate of return on assets has been determined using an asset model that takes into account the allocation of assets among various asset classes, the expected rate of return on each asset class, the variability of returns and the correlation of returns among asset classes.

An increase of one percent in the assumed health care cost trend rate would increase the aggregate of the current service cost and interest cost components of other benefit expense by $23,100 and increase the defined benefit obligation for these plans by $261,000. A decrease of one percent in the assumed health care cost trend rate would decrease the aggregate of the current service cost and interest cost components of other benefit expense by $30,800 and decrease the defined benefit obligation for these plans by $316,800.

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

	Pension Benefit Plans				Other Benefit Plans
	2011		2010		2011		2010
Balance at beginning of year	$	574	$	—	$	—	$	—
Recognized during the year		13,496		574		1,803		—
	$	14,070	$	574	$	1,803	$	—

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The following table presents historical information on both the pension and other benefit plans:

	Pension Benefit Plans						Other Benefit Plans
	2011			2010			2011			2010
Fair value of plan assets	$	21,766		$	27,135		$	—		$	—
Present value of defined benefit obligation		44,111			35,518			16,276			13,355
Deficit in the plan	$	(22,345	)	$	(8,383	)	$	(16,276	)	$	(13,355	)
Experience adjustments arising on plan assets		(2.6	)%		10.9	%		—			—
Experience adjustments arising on plan liabilities		29.3	%		10.0	%		11.1	%		—

The following are the contributions expected to be paid to the plans during the annual period beginning after the end of the current reporting period:

	2012
Employer contribution to funded pension plans	$	11,898
Benefits paid for unfunded benefit plans		788
Cash contributions to defined contribution plans		17,329

BPLP

BPLP has a funded registered pension plan and an unfunded supplemental pension plan. The funded plan is a contributory, defined benefit plan covering all employees up to the limits imposed by the Income Tax Act. The supplemental pension plan is a non-contributory, defined benefit plan covering all employees with respect to benefits that exceed the limits under the Income Tax Act. These plans are based on years of service and final average salary.

BPLP also has other post-retirement benefit and other post-employment benefit plans that provide for group life insurance, health care and long-term disability benefits. These plans are non-contributory.

The effective date for the most recent valuations for funding purposes on the pension benefit plans is January 1, 2011. The next planned effective date for valuation for funding purposes of the pension benefit plans is set to be January 1, 2012. The status of Cameco’s proportionate share (31.6%) of the defined plans is as follows:

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A reconciliation of the funded status of the benefit plans to the financial statements is as follows:

	Pension Benefit Plans						Other Benefit Plans
	2011			2010			2011			2010
Fair value of plans assets, beginning of year	$	717,320		$	635,293		$	—		$	—
Expected return on plan assets		50,484			44,490			—			—
Actuarial gain (loss)		(26,300	)		11,692
Employer contributions		41,294			50,012			—			—
Plan participants’ contributions		7,900			6,630			—			—
Benefits paid		(32,046	)		(30,797	)		—			—
Fair value of plan assets, end of year	$	758,652		$	717,320		$	—		$	—
Defined benefit obligation, beginning of year	$	887,419		$	711,636		$	181,011		$	151,826
Current service cost		26,752			18,329			9,312			7,422
Interest cost		47,122			42,478			9,424			8,960
Actuarial loss		81,064			139,143			16,029			17,291
Plan participants’ contributions		7,900			6,630			—			—
Benefits paid		(32,804	)		(30,797	)		(4,683	)		(4,488	)
Defined benefit obligation, end of year	$	1,017,453		$	887,419		$	211,093		$	181,011
Funded status of plans - deficit	$	(258,801	)	$	(170,099	)	$	(211,093	)	$	(181,011	)
Unrecognized past service cost		—			—			1,531			1,981
Defined benefit liability [note 18]	$	(258,801	)	$	(170,099	)	$	(209,562	)	$	(179,030	)

The actual return on plan assets for the pension benefit plans for the year ended December 31, 2011 was $24,184,000 (2010 - $56,182,000).

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

	Asset Allocation						Target Allocation
	2011			2010			2011			2010
Asset Category (i)
Equity securities		55	%		59	%		60	%		60	%
Fixed income		43	%		39	%		40	%		40	%
Cash		2	%		2	%		—			—
Total		100	%		100	%		100	%		100	%

⁽ⁱ⁾  The defined benefit plan assets contain no material amounts of related party assets at December 31, 2011.

The assets of the pension plan are managed on a going concern basis subject to legislative restrictions. The plan’s investment policy is to maximize returns within an acceptable risk tolerance. Pension assets are invested in a diversified manner with consideration given to the demographics of the plan participants.

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The following represents the components of net pension and other benefit expense included primarily as part of cost of products and services sold:

	Pension Benefit Plans						Other Benefit Plans
	2011			2010			2011		2010
Current service cost	$	26,752		$	18,329		$	9,312	$	7,422
Interest cost		47,122			42,478			9,424		8,960
Expected return on plan assets		(50,484	)		(44,490	)		—		—
Past service cost		—			—			450		450
Net pension and other benefit expense	$	23,390		$	16,317		$	19,186	$	16,832

The assumptions used to determine BPLP’s defined benefit obligation and net pension and other benefit expense related to the pension benefit and other benefit plans were as follows:

	Pension Benefit Plans						Other Benefit Plans
	2011			2010			2011			2010
Discount rate		4.8	%		5.3	%		4.6	%		5.1	%
Rate of compensation increase		3.5	%		3.5	%		3.5	%		3.5	%
Long-term rate of return on assets		7.0	%		7.0	%		—			—
Initial health care cost trend rate		—			—			8.5	%		9.5	%
Cost trend rate declines to		—			—			5.0	%		5.0	%
Year the rate reaches its final level		—			—			2019			2019

The overall expected rate of return is a weighted average of the expected returns of the various categories of plan assets held. The assessment of the expected returns is based on historical return trends with reference to market interest rates at the measurement date on high-quality debt instruments with cash flows that match the timing and amount of expected future benefit payments.

An increase of one percent in the assumed health care cost trend rate would increase the aggregate of the current service cost and interest cost components of other benefit expense by $3,661,000 and increase the defined benefit obligation for these plans by $35,363,000. A decrease of one percent in the assumed health care cost trend rate would decrease the aggregate of the current service cost and interest cost components of other benefit expense by $2,736,000 and decrease the defined benefit obligation for these plans by $27,554,000.

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

	Pension Benefit Plans				Other Benefit Plans
	2011		2010		2011		2010
Balance at beginning of year	$	127,451	$	—	$	17,291	$	—
Recognized during the year		107,364		127,451		16,029		17,291
	$	234,815	$	127,451	$	33,320	$	17,291

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The following table presents historical information on both the pension and other benefit plans:

	Pension Benefit Plans						Other Benefit Plans
	2011			2010			2011			2010
Fair value of plan assets	$	758,652		$	717,320		$	—		$	—
Present value of defined benefit obligation		1,017,453			887,419			211,093			181,011
Deficit in the plan	$	(258,801	)	$	(170,099	)	$	(211,093	)	$	(181,011	)
Experience adjustments arising on plan assets		(3.5	)%		1.6	%		—			—
Experience adjustments arising on plan liabilities		8.0	%		15.7	%		7.6	%		9.6	%

The following are the contributions expected to be paid to the plans during the annual period beginning after the end of the current reporting period:

	2012
Employer contribution to funded pension plans	$	73,786
Benefits paid for unfunded benefit plans		6,162

29. 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.

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To mitigate risks associated with fluctuations in the market price for electricity, BPLP enters into various fixed price energy sales contracts that qualify as cash flow hedges. These instruments have terms ranging from 2012 to 2016. The periods in which the cash flows associated with these cash flow hedges are expected to occur and when they are expected to impact earnings are as follows:

	Cash flows		Earnings impact
2012	$	20,373	$	15,879
2013		5,526		3,555
2014		556		237
2015		82		—
2016		1		—
Total	$	26,538	$	19,671

The maximum length of time BPLP is hedging its exposure to the variability in future cash flows related to electricity prices on anticipated transactions is six years. For the year ended December 31, 2011, a net unrealized loss of $3,141,000 (2010 – net unrealized loss of $2,998,000) was recognized for the ineffective portion of cash flow hedges.

At December 31, 2011, the effect of a $1/MWh increase in the market price for electricity would be a decrease of $171,000 in net earnings and a decrease in other comprehensive income of $868,000 for 2011.

(b) Foreign Exchange Risk

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

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 fuel services, is denominated in US dollars.

At December 31, 2011, the effect of a $0.01 increase in the US to Canadian dollar exchange rate on our portfolio of currency hedges and other US denominated exposures would have been a decrease of $9,800,000 in net earnings for 2011.

(c) Interest Rate Risk

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 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, 2011, the mark-to-market gain on Cameco’s interest rate swaps and caps less premiums paid was $7,165,000 (2010 - $1,458,000).

At December 31, 2011, the effect of a 1% increase in the three-month bankers’ acceptance rate would be a decrease in net earnings of $3,260,000.

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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.

Cameco is exposed to credit risk on its cash and cash equivalents, short-term investments, accounts receivable and derivative assets. The maximum exposure to credit risk, as represented by the carrying amount of the financial assets at December 31, was:

	2011		2010		Jan 1/10
Cash and cash equivalents	$	399,279	$	376,621	$	1,101,229
Short-term investments		804,141		883,032		202,836
Accounts receivable		595,506		433,386		431,783
Derivative assets		71,402		127,842		210,381

At December 31, 2011, 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.

The table below outlines the Company’s available debt facilities at December 31, 2011:

	Total Amount		Outstanding and Committed		Amount Available
Unsecured revolving credit facility	$	1,250,000	$	—	$	1,250,000
Letter of credit facility		693,094		693,094		—
Inkai revolving credit facility (Cameco’s share)		12,204		6,126		6,078
BPLP working capital and operational letter of credit facility (Cameco’s share) (a)		47,400		23,700		23,700
BPLP letter of credit facilities (Cameco’s share)		130,190		114,390		15,800

(a) The amount outstanding and committed includes $18,644,000 relating to working capital and $5,056,000 of operational letters of credit.

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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
Accounts payable and accrued liabilities	$	457,307	$	457,307	$	457,307	$	—	$	—	$	—
Short-term debt		91,703		91,703		91,703		—		—		—
Long-term debt		801,271		806,126		—		6,126		300,000		500,000
BPLP lease		145,834		145,834		14,852		34,572		43,192		53,218
Energy and sales contracts		20,078		20,078		16,913		2,752		413		—
Foreign currency contracts		26,555		26,555		26,555		—		—		—
Interest rate contracts		1,305		1,305		—		—		1,305		—
Total contractual repayments	$	1,544,053	$	1,548,908	$	607,330	$	43,450	$	344,910	$	553,218
			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			$	2,007	$	2,007	$	—	$	—	$	—
Interest on long-term debt				270,210		42,609		85,156		66,688		75,757
Interest on BPLP lease				43,450		10,435		17,252		11,475		4,288
Total interest payments			$	315,667	$	55,051	$	102,408	$	78,163	$	80,045

Fair Value

All financial instruments measured at fair value 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 measurement 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.

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 measure in its entirety.

Except as otherwise disclosed, the fair market value of Cameco’s financial assets and liabilities approximates the carrying amount as a result of the short-term nature of the instruments, or 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 available-for-sale securities, as described in note 12, has not been disclosed because of the unavailability of a quoted market price in an active market. Cameco does not currently have plans to dispose of this investment.

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The following tables present Cameco’s fair value hierarchy for those assets and liabilities measured at fair value on a recurring basis.

As at December 31, 2011
	Level 1		Level 2			Level 3			Total
Derivative instrument assets	$	—	$	69,190		$	2,212		$	71,402
Available-for-sale securities [notes 7,12]		804,141		—			—			804,141
Derivative instrument liabilities		—		(47,622	)		(316	)		(47,938	)
Net	$	804,141	$	21,568		$	1,896		$	827,605
As at December 31, 2010
	Level 1		Level 2			Level 3			Total
Derivative instrument assets	$	—	$	122,786		$	5,056		$	127,842
Available-for-sale securities [notes 7,12]		889,065		—			—			889,065
Derivative instrument liabilities		—		(35,227	)		—			(35,227	)
Net	$	889,065	$	87,559		$	5,056		$	981,680
As at January 1, 2010
	Level 1		Level 2			Level 3			Total
Derivative instrument assets	$	—	$	197,381		$	13,000		$	210,381
Available-for-sale securities [notes 7,12]		207,473		—			—			207,473
Derivative instrument liabilities		—		(39,957	)		(1,000	)		(40,957	)
Net	$	207,473	$	157,424		$	12,000		$	376,897

The fair value of a financial instrument is the amount at which the financial instrument could be exchanged in an arm’s-length transaction between knowledgeable and willing parties under no compulsion to act. Fair values of identical instruments traded in active markets are determined by reference to last quoted prices, in the most advantageous active market for that instrument. In the absence of an active market, we determine fair values based on quoted prices for instruments with similar characteristics and risk profiles. Fair values of financial instruments determined using valuation models require the use of inputs. In determining those inputs, we look primarily to external, readily observable market inputs, when available, including factors such as interest rate yield curves, currency rates, and price and rate volatilities, as applicable. In some circumstances, we use input parameters that are not based on observable market data. In these cases, we may adjust model values to reflect the valuation uncertainty in order to determine what the fair value would be based on the assumptions that market participants would use in pricing the financial instrument. These adjustments are made in order to determine the fair value of the instruments.

We make valuation adjustments for the credit risk of our derivative portfolios in order to arrive at their fair values. These adjustments take into account the creditworthiness of our counterparties.

Financial instruments classified as available-for-sale comprise actively traded debt and equity securities and are carried at fair value based on available quoted prices.

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There were no significant transfers between level 1 and level 2 of the fair value hierarchy. The following table presents a reconciliation of the beginning and ending balances of those financial instruments in level 3 of the fair value hierarchy:

	2011			2010
Balance at beginning of year	$	5,056		$	12,000
Losses recognized in earnings		632			12,324
Unrealized losses previously recognized in other components of equity		632			3,476
Transfers into level 3		—			2,528
Transfers out of level 3		(4,424	)		(25,272	)
	$	1,896		$	5,056

Transfers into level 3 are comprised of BPLP derivative financial instruments with contract terms extending beyond 36 months.

Derivatives

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

As at December 31, 2011

	Cameco			BPLP			Total
Non-hedge derivatives:
Embedded derivatives - sales contracts	$	(639	)	$	8,033		$	7,394
Foreign currency contracts		(17,633	)		—			(17,633	)
Interest rate contracts		7,165			—			7,165
Cash flow hedges:
Energy and sales contracts		—			26,538			26,538
Net	$	(11,107	)	$	34,571		$	23,464
Classification:
Current portion of long-term receivables, investments and other [note 12]	$	8,922		$	42,088		$	51,010
Long-term receivables, investments and other [note 12]		8,470			11,922			20,392
Current portion of other liabilities [note 18]		(26,555	)		(16,913	)		(43,468	)
Other liabilities [note 18]		(1,944	)		(2,526	)		(4,470	)
Net	$	(11,107	)	$	34,571		$	23,464

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As at December 31, 2010
	Cameco			BPLP			Total
Non-hedge derivatives:
Embedded derivatives - sales contracts	$	(3,864	)	$	18,877		$	15,013
Foreign currency contracts		47,144			—			47,144
Interest rate contracts		1,458			—			1,458
Cash flow hedges:
Energy and sales contracts		—			29,000			29,000
Net	$	44,738		$	47,877		$	92,615
Classification:
Current portion of long-term receivables, investments and other [note 12]	$	46,629		$	44,505		$	91,134
Long-term receivables, investments and other [note 12]		3,382			33,326			36,708
Current portion of other liabilities [note 18]		(377	)		(20,662	)		(21,039	)
Other liabilities [note 18]		(4,896	)		(9,292	)		(14,188	)
Net	$	44,738		$	47,877		$	92,615
As at January 1, 2010
	Cameco			BPLP			Total
Non-hedge derivatives:
Embedded derivatives - sales contracts	$	(2,736	)	$	9,082		$	6,346
Foreign currency contracts		67,031			—			67,031
Cash flow hedges:
Energy and sales contracts		—			96,047			96,047
Net	$	64,295		$	105,129		$	169,424
Classification:
Current portion of long-term receivables, investments and other [note 12]	$	66,972		$	87,439		$	154,411
Long-term receivables, investments and other [note 12]		1,460			54,510			55,970
Current portion of other liabilities [note 18]		(445	)		(19,595	)		(20,040	)
Other liabilities [note 18]		(3,692	)		(17,225	)		(20,917	)
Net	$	64,295		$	105,129		$	169,424

The following tables summarize different components of the gains (losses) on derivatives:

For the year ended December 31, 2011
	Cameco			BPLP			Total
Non-hedge derivatives:
Embedded derivatives - sales contracts	$	3,264		$	(952	)	$	2,312
Foreign currency contracts		(11,586	)		—			(11,586	)
Interest rate contracts		7,998			—			7,998
Cash flow hedges:
Energy and sales contracts		—			(3,141	)		(3,141	)
Net	$	(324	)	$	(4,093	)	$	(4,417	)

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For the year ended December 31, 2010
	Cameco			BPLP			Total
Non-hedge derivatives:
Embedded derivatives - sales contracts	$	(1,623	)	$	(2,785	)	$	(4,408	)
Foreign currency contracts		80,107			—			80,107
Interest rate contracts		2,482			—			2,482
Cash flow hedges:
Energy and sales contracts		—			(2,998	)		(2,998	)
Net	$	80,966		$	(5,783	)	$	75,183

30. 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 and by acquisition. Our capital resources are managed to support achievement of our goals. The overall objectives for managing capital remained unchanged in 2011 from the prior comparative period.

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

The capital structure at December 31, 2011 was as follows:

	2011			2010			Jan 1/10
Long-term debt	$	801,271		$	794,483		$	793,842
Finance lease obligation		145,834			159,011			170,640
Short-term debt		91,703			85,588			87,506
Cash and cash equivalents		(399,279	)		(376,621	)		(1,101,229	)
Short-term investments		(804,141	)		(883,032	)		(202,836	)
Net debt		(164,612	)		(220,571	)		(252,077	)
Non-controlling interest		185,938			178,139			164,040
Shareholders’ equity		4,919,567			4,690,313			4,426,060
Total equity		5,105,505			4,868,452			4,590,100
Total capital	$	4,940,893		$	4,647,881		$	4,338,023

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, 2011, Cameco met these requirements.

31. Commitments and Contingencies

(a) On February 12, 2004, Cameco, Cameco Bruce Holdings II Inc., BPC Generation Infrastructure Trust (“BPC”) and TransCanada Pipelines Limited (“TransCanada”) (collectively, the “Consortium”), sent a notice of claim to British Energy Limited and British Energy International Holdings Limited (collectively, “BE”) requesting, amongst other things, indemnification for breach of a representation and warranty contained in the February 14, 2003, Amended and Restated Master Purchase Agreement. The alleged breach is that the Unit 8 steam generators were not “in good condition, repair and proper working order, having regard to their use and age.” This defect was discovered during a planned outage conducted just after closing. As a result of this defect, the planned outage had to be significantly extended. The Consortium has claimed damages in the amount of $64,558,200 being 79.8% of the $80,900,000 of damages actually incurred, plus an unspecified amount to take into account the reduced operating life of the steam generators. By agreement of the parties, an arbitrator has been appointed to arbitrate the claims.

The Consortium served its claim on October 21, 2008, and has amended it as required, most recently on August 7, 2009. BE served its answer and counter-statement on December 22, 2008, most recently amended on March 25, 2010, and the Consortium served its reply and answer to counter-statement on January 22, 2009, most recently amended on August 7, 2009.

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The Unit 8 steam generators require on-going monitoring and maintenance as a result of the defect. In addition to the $64,558,200 in damages sought in the notice of claim, the claim seeks an additional $4,900,000 spent on inspection, monitoring and maintenance of Unit 8, and $31,900,000 in costs for future monitoring and maintenance, as well as repair costs and lost revenue due to anticipated unplanned outages as a consequence of the defect in Unit 8. The initial claim had also sought damages for the early replacement of the Unit 8 steam generators due to the defect shortening their useful operating lives. However, subsequent inspection data and analysis of the condition of the Unit 8 steam generators indicates that they will continue to function until the end of the Consortium’s lease of the Bruce Power facility in 2018, as was expected at the time the MPA was entered into. The claim for early replacement was thus abandoned via an amendment to the claim on August 7, 2009. The arbitration hearing was completed on November 23, 2010 and final oral arguments were heard July 19 through 21, 2011 and a decision is pending.

In anticipation of this claim, BE issued on February 10, 2006, and then served on Ontario Power Generation Inc. (“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, damages in the amount of $500,000,000, costs and pre and post judgment interest amongst other things. Further proceedings in this action are on hold pending completion of the arbitration hearing.

(b) Annual supplemental rents of $30,000,000 (subject to CPI) per operating reactor are payable by BPLP to Ontario Power Generation Inc. (“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.

(c) Cameco, TransCanada and BPC have assumed the obligations to provide financial guarantees on behalf of BPLP. Cameco has provided the following financial assurances, with varying terms that range from 2012 to 2018:

i) Guarantees to customers under power sales agreements of up to $19,000,000. At December 31, 2011, Cameco’s actual exposure under these agreements was $10,800,000.

ii) Termination payments to OPG pursuant to the lease agreement of $58,300,000. The fair value of these guarantees 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. BPLP’s entitlement to receive these payments remains in effect until December 31, 2019 but the generation that is subject to these payments starts to decrease in 2016, reflecting the original estimated lives for the Bruce B units. During 2011, BPLP recorded $498,000,000 under this agreement which was recognized as revenue with Cameco’s share being $157,000,000.

32. Segmented Information

Cameco has three reportable segments: uranium, fuel services and electricity. 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.

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, 2011
	Uranium			Fuel Services			Electricity		Other			Total
Revenue	$	1,615,697		$	305,280		$	427,927	$	35,500		$	2,384,404
Expenses
Products and services sold		824,324			224,548			247,665		36,912			1,333,449
Depreciation and amortization		159,168			26,579			71,247		17,841			274,835
Cost of sales		983,492			251,127			318,912		54,753			1,608,284
Gross profit (loss)		632,205			54,153			109,015		(19,253	)		776,120
Exploration		95,924			—			—		—			95,924
Cigar Lake remediation		4,363			—			—		—			4,363
Loss on disposal of assets		7,602			—			—		—			7,602
Share of loss from equity-accounted investees		4,533			2,700			—		—			7,233
Other income		(2,538	)		(2,382	)		—		—			(4,920	)
Non-segmented expenses													215,528
Earnings (loss) before income taxes		522,321			53,835			109,015		(19,253	)		450,390
Income tax expense													11,755
Net earnings												$	438,635
Assets	$	6,514,712		$	490,046		$	797,073	$	—		$	7,801,831
Capital expenditures for the year	$	552,630		$	17,918		$	76,662	$	—		$	647,210
For the year ended December 31, 2010
	Uranium			Fuel Services			Electricity		Other			Total
Revenue	$	1,357,830		$	286,582		$	476,749	$	2,494		$	2,123,655
Expenses
Products and services sold		691,281			202,054			219,860		768			1,113,963
Depreciation and amortization		134,928			19,704			64,295		19,381			238,308
Cost of sales		826,209			221,758			284,155		20,149			1,352,271
Gross profit (loss)		531,621			64,824			192,594		(17,655	)		771,384
Exploration		95,796			—			—		—			95,796
Cigar Lake remediation		16,633			—			—		—			16,633
Loss on disposal of assets		107			—			—		—			107
Share of loss from equity-accounted investees		1,224			2,952			—		—			4,176
Other income		(4,388	)		—			—		—			(4,388	)
Non-segmented expenses													149,594
Earnings (loss) before income taxes		422,249			61,872			192,594		(17,655	)		509,466
Income tax expense													3,427
Net earnings												$	506,039
Assets	$	5,952,911		$	464,636		$	785,007	$	—		$	7,202,554
Capital expenditures for the year	$	367,408		$	20,230		$	42,944	$	—		$	430,582

63

(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:

	2011		2010
Canada	$	719,454	$	791,810
United States		1,664,950		1,331,845
	$	2,384,404	$	2,123,655

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

	2011		2010
Canada	$	3,553,599	$	3,089,664
United States		305,976		208,912
Australia		612,438		596,150
Other		159,048		154,191
	$	4,631,061	$	4,048,917

64

33. Group Entities

The following are the principal subsidiaries, associates and jointly controlled entities of the Company:

			Ownership Interest
	Country of Incorporation		2011			2010
Subsidiaries:
Cameco Bruce Holdings Inc.		Canada		100	%		100	%
Cameco Bruce Holdings II Inc.		Canada		100	%		100	%
Cameco Royalty Inc.		Canada		100	%		100	%
Cameco India Limited		Canada		100	%		100	%
alphaNUCLEAR Inc.		Canada		100	%		100	%
Cameco Global Exploration Ltd.		Canada		100	%		100	%
Northern Basins Uranium Ltd.		Canada		100	%		51	%
Cameco Global Exploration II Ltd.		Canada		100	%		100	%
Cameco Fuel Holdings Inc.		Canada		100	%		100	%
Cameco Fuel Manufacturing Inc.		Canada		100	%		100	%
Cameco Property Holdings Inc.		Canada		100	%		100	%
Cameco UFP Holdings Canada Ltd.		Canada		100	%		100	%
Cameco U.S. Holdings, Inc.		U.S.		100	%		100	%
Cameco Inc.		U.S.		100	%		100	%
Power Resources, Inc.		U.S.		100	%		100	%
Crow Butte Resources, Inc.		U.S.		100	%		100	%
Cameco Enrichment Holdings LLC		U.S.		100	%		100	%
Cameco UFP Holdings LLC		U.S.		100	%		100	%
UFP Investments LLC		U.S.		53	%		32	%
Cameco Ireland Company		Ireland		100	%		100	%
Cameco Australia Pty. Ltd.		Australia		100	%		100	%
Cameco Uranium Inc.		Barbados		100	%		100	%
Cameco Luxembourg S.A.		Luxembourg		100	%		100	%
Cameco Investments AG		Switzerland		100	%		100	%
Cameco Europe Ltd.		Switzerland		100	%		100	%
Cameco Europe (Central Asia) Ltd.		Switzerland		100	%		n/a
Cameco Services Inc.		Barbados		100	%		100	%
Cameco Insurance Services Inc.		Barbados		100	%		100	%
Cameco Global South America Inc.		Barbados		100	%		n/a
Netherlands International Uranium B.V.		Netherlands		100	%		100	%
Cameco Mongolia LLC		Mongolia		100	%		100	%
Cameco Kazakhstan LLP		Kazakhstan		100	%		100	%
CamFin OY		Finland		100	%		100	%
Kintyre Uranium Project Joint Venture		Australia		70	%		70	%
Associates:
GE-Hitachi Global Laser Enrichment LLC		U.S.		24.00	%		24.00	%
UEX Corporation		Canada		22.58	%		22.61	%
Huron Wind		Canada		33.33	%		33.33	%
Minergia S.A.C.		Peru		50.00	%		50.00	%
UrAmerica Ltd.		England		19.90	%		n/a

65

34. Jointly Controlled Assets

Cameco conducts a portion of its exploration, development, mining and milling activities through joint ventures. Cameco’s significant uranium joint venture interests are McArthur River, Key Lake and Cigar Lake. Uranium joint ventures allocate uranium production to each joint venture participant and the joint venture participant derives revenue directly from the sale of such product. Mining and milling expenses incurred by the joint venture are included in the cost of inventory.

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

	Ownership			2011		2010		Jan 1/10
Total Assets
McArthur River		69.81	%	$	972,184	$	905,652	$	861,363
Key Lake		83.33	%		523,690		458,171		385,275
Cigar Lake		50.03	%		889,140		723,723		618,837
				$	2,385,014	$	2,087,546	$	1,865,475
Total Liabilities
McArthur River		69.81	%	$	45,753	$	35,632	$	28,134
Key Lake		83.33	%		105,033		86,623		75,122
Cigar Lake		50.03	%		45,270		24,128		15,668
				$	196,056	$	146,383	$	118,924

35. Jointly Controlled Entities

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. Cameco uses the proportionate consolidation method to account for its 31.6% interest in BPLP. Cameco also holds a 60% interest in the Inkai joint venture, which is governed by an agreement that provides for joint control of the strategic operating, investing and financing activities among the two venturers. Cameco uses the proportionate consolidation method to account for its 60% interest in Inkai.

The following schedules reflect Cameco’s proportionate interest in the assets, liabilities, revenue and expenses of the BPLP partnership:

	2011			2010			Jan 1/10
Current assets	$	225,719		$	207,896		$	253,369
Non-current assets		502,250			502,250			544,942
Current liabilities		(155,504	)		(128,106	)		(129,623	)
Non-current liabilities		(605,993	)		(502,377	)		(404,512	)
Net assets (liabilities)	$	(33,528	)	$	79,663		$	264,176

	2011			2010
Revenue	$	427,927		$	476,749
Expenses		(329,605	)		(298,245	)
Net earnings	$	98,322		$	178,504

66

The following schedule reflects Cameco’s proportionate interest in the assets and liabilities of the Inkai joint venture:

	2011			2010			Jan 1/10
Current assets	$	54,968		$	84,013		$	60,501
Non-current assets		198,831			190,340			189,832
Current liabilities		(10,959	)		(9,291	)		(15,809	)
Non-current liabilities		(136,908	)		(197,275	)		(216,648	)
Net assets	$	105,932		$	67,787		$	17,876

Through an unsecured shareholder loan, Cameco has agreed to fund the development of the Inkai project. On proportionate consolidation of Inkai, Cameco eliminates the loan balance recorded by Inkai and records advances receivable (notes 12 & 37) representing its 40% ownership interest.

The following schedule reflects Cameco’s proportionate interest in the revenue and expenses of the Inkai joint venture:

	2011			2010
Revenue	$	132,845		$	137,079
Expenses		(78,517	)		(90,566	)
Net earnings	$	54,328		$	46,513

The participants in the Inkai joint venture purchase uranium from Inkai, and, in turn, derive revenue directly from the sale of such product to third party customers. On proportionate consolidation of Inkai, Cameco eliminates revenues and cost of sales recorded by Inkai related to sales by Inkai to Cameco.

36. Acquisition of Controlling Interest in UFP Investments LLC (“UFP”)

On November 9, 2009, Cameco, through a wholly-owned subsidiary entered into a strategic alliance agreement whereby Cameco could acquire a controlling interest in UFP through the funding of a series of investment tranches. On June 20, 2011, Cameco increased its ownership interest in UFP to a controlling 53.0% at a total cost of $12,500,000 (US). The strategic alliance agreement provides Cameco the right to earn an additional 17% interest in UFP through the funding of an additional $4,000,000 (US). UFP is in the process of developing uranium from phosphate extraction technology. The purchase price was financed with cash. The acquisition of UFP was accounted for as an asset acquisition and the cost was allocated to the acquired net assets based on the relative fair values.

37. 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 28). Senior management and directors also participate in the Company’s share-based compensation plans (note 27).

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.

67

Compensation for key management personnel was comprised of:

	2011		2010
Short-term employee benefits	$	24,887	$	26,312
Post-employment benefits		5,949		5,575
Share-based compensation (a)		10,808		7,216
	$	41,644	$	39,103

(a) Excludes deferred share units held by directors (see note 27).

Certain key management personnel, or their related parties, hold positions in other entities that result in them having control or significant influence over the financial or operating policies of those entities. As noted below, one of these entities transacted with the Company in the reporting period. The terms and conditions of the transactions were on an arm’s length basis.

Cameco purchases a significant amount of goods and services for its Saskatchewan mining operations from northern Saskatchewan suppliers to support economic development in the region. One such supplier is Points Athabasca Contracting Ltd. and the president of the company became a member of the board of directors of Cameco during 2009. In 2011, Cameco paid Points Athabasca Contracting Ltd. $63,000,000 (2010 - $38,000,000) for construction and contracting services. The transactions were conducted in the normal course of business and were accounted for at the exchange amount. Accounts payable include a balance of $1,540,000 (2010 - $2,290,000).

Other Related Party Transactions
	Transaction Value Year ended						Balance Outstanding As at
	2011			2010			2011			2010
Sale of goods and services
Jointly Controlled Entities - BPLP (a)	$	31,926		$	38,196		$	19,557		$	22,226
Other
Jointly Controlled Entities - JV Inkai LLP (interest income) (a)		2,208			3,420			78,058			125,072
Associates (interest expense)		(1,597	)		(2,005	)		(73,468	)		(78,155	)

(a) Disclosures in respect of transactions with jointly controlled entities 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 an unsecured shareholder loan, Cameco has agreed to fund the development of the Inkai project. The limit of the loan facility is $370,000,000 (US) and advances under the facility bear interest at a rate of LIBOR plus 2%. At December 31, 2011, $191,882,000 (US) of principal and interest was outstanding (December 31, 2010 - $314,378,000 (US)).

In 2008, a promissory note in the amount of $73,344,000 (US) was issued to finance the acquisition of GE-Hitachi Global Laser Enrichment LLC (GLE) The promissory note is payable on demand and bears interest at market rates. At December 31, 2011, $72,240,000 (US) of principal and interest was outstanding (December 31, 2010 - $78,579,000 (US)).

68

EX-99.3

EXHIBIT 99.3

Cameco Corporation

2011 Management’s Discussion and Analysis

February 9, 2012

Management’s discussion and analysis

February 9, 2012

2011 Highlights	4
The nuclear fuel cycle	7
About Cameco	8
The nuclear industry today	11
The long-term view	14
Our strategy	17
Financial results	32
Our operations and development projects	61
Mineral reserves and resources	96
Additional information	101

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

Management’s discussion and analysis

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, 2011. This information is based on what we knew on February 8, 2012.

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.

On January 1, 2011, we adopted International Financial Reporting Standards (IFRS), which have become the generally accepted accounting principles required to be used by most Canadian publicly accountable enterprises. Our financial statements and notes for the year ended December 31, 2011 have been prepared using IFRS. Amounts relating to the year ended December 31, 2010 in this MD&A and our financial statements have been revised to reflect our adoption of IFRS. Amounts for periods prior to January 1, 2010 are presented in accordance with Canadian Generally Accepted Accounting Principles (Canadian GAAP) in effect prior to January 1, 2011. When we refer to Canadian GAAP in this MD&A, we mean Canadian GAAP as in effect before adoption of IFRS.

Presentation and terminology used in our financial statements and this MD&A differ from that used in previous years. Details of the more significant accounting differences can be found in note 3 to our financial statements.

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

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    1

Caution about forward-looking information

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

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

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

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

• It is based on a number of material assumptions, including those we have listed on page 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 page 3. We recommend you also review our annual information form, which includes a discussion of other material risks that could cause actual results to differ significantly from our current expectations.

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

Examples of forward-looking information in this MD&A

• our expectations about 2012 and future global uranium supply, consumption, demand and number of operable reactors, including the discussion on the expected impact resulting from the March 2011 nuclear incident in Japan

• our expectations for spot prices in 2012

• our strategy for increasing annual production to 40 million pounds by 2018 and our expectation that existing cash balances and operating cash flows will meet anticipated capital requirements without the need for any significant additional financing to reach this goal

• our expectations regarding uranium demand in the near term

• our 2012 objectives

• the outlook for each of our operating segments for 2012, and our consolidated outlook for the year

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

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

• our expectations for 2012, 2013 and 2014 capital expenditures

• our expectation that our operating and investment activities in 2012 will not be constrained by the financial covenants in our unsecured revolving credit facility

• our uranium price sensitivity analysis

• forecast production at our uranium operations from 2012 to 2016

• the likely terms and volumes to be covered by long-term delivery contracts that we enter into in 2012 and in future years

• future production at our fuel services operations

• future royalty and tax payments and rates

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

• our expectations regarding Cigar Lake

• our mineral reserve and resource estimates

2    CAMECO CORPORATION

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, or are subject to litigation or arbitration that has an adverse outcome

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

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

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

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

• we are affected by political risks in a developing country where we operate

• we are affected by terrorism, sabotage, blockades, civil unrest, 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 fulfil delivery commitments

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

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

• our operations are disrupted due to problems with our own or our customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, lack of tailings capacity, labour shortages, labour relations issues, 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 adversely affected by changes in regulation or in the public perception of the safety of nuclear power plants

• our expected production level and production costs

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

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

• our decommissioning and reclamation expenses

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

• the geological, hydrological and other conditions at our mines

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

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

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

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

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    3

2011 Highlights

After a year of global economic, political and environmental challenges, we reassessed our corporate growth strategy and found it to be as relevant today as it was in 2008 when we set our Double U course. We remain confident in the long-term fundamentals of the nuclear industry. World demand for safe, clean, reliable and affordable energy continues to grow and the need for nuclear energy as part of the world’s energy mix remains compelling.

We are preparing our assets to ensure we can be among the first to respond when the market signals new production is needed and to maintain our position as one of the world’s largest uranium producers.

We demonstrated our financial strength again this year and we continued to make good progress on our pipeline of projects in development and under evaluation, hitting some key milestones along the way.

Strong financial performance

Our financial results were better than expected and we achieved a number of performance records for the year and during the fourth quarter, including:

• annual revenue of $2.4 billion and quarterly revenue of $977 million from our nuclear business

• annual gross profit of $776 million and quarterly gross profit of $353 million from our nuclear business

• annual revenue of $1.6 billion and quarterly revenue of $731 million from our uranium segment

• annual average realized price of $49.18 per pound ($49.17 US per pound) in our uranium segment

Net earnings attributable to our shareholders (net earnings) in 2011 were $450 million. In 2010, net earnings were higher by $66 million, mainly due to higher earnings in both our electricity and fuel services segments.

Highlights December 31 ($ millions except where indicated)			2011		2010		change
Revenue				2,384		2,124		12	%
Gross profit				776		771		1	%
Net earnings				450		516		(13	)%
$ per common share (diluted)				1.14		1.31		(13	)%
Adjusted net earnings (non-IFRS, see page 33 & 34)				509		497		2	%
$ per common share (adjusted and diluted)				1.29		1.26		2	%
Cash provided by operations (after working capital changes)				732		521		40	%
Average realized prices	Uranium	$US/lb $Cdn/lb		49.17 49.18		43.63 45.81		13 7	%  %
	Fuel services	$Cdn/kgU		16.71		16.86		(1	)%
	Electricity	$Cdn/MWh		54		58		(7	)%

Shares and stock options outstanding

At February 9, 2012, we had:

• 394,767,078 common shares and one Class B share outstanding

• 8,442,385 stock options outstanding, with exercise prices ranging from $10.51 to $46.88

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.

4    CAMECO CORPORATION

Excellent progress in our uranium segment this year

In our uranium segment this year, production was 3% higher than the guidance we provided in our 2011 third quarter MD&A. We had a number of successes at our mining operations, development projects and projects under evaluation. Key highlights:

• realized benefits of production flexibility provisions in our McArthur River/Key Lake licences, matching our 2010 production record and exceeding our production target by 5%

• realized benefits of improved efficiency and reliability of equipment at Key Lake

• completed construction of the acid, steam and oxygen plants at Key Lake

• signed a memorandum of agreement (MOA) to increase production at Inkai from 3.9 million pounds (100% basis) to 5.2 million pounds (100% basis). See Uranium – operating properties – Inkai on page 79 for more information.

• signed an agreement to process all Cigar Lake ore at the McClean Lake mill, which is expected to result in a significant reduction in the operating cost of the project. See Uranium – development project – Cigar Lake on page 83 for more information.

• completed remediation of the underground and sinking of shaft 2 to the 480 metre level at Cigar Lake

• received regulatory approval for our Cigar Lake mine plan and to begin work on our project to allow the release of treated water directly to Seru Bay

• completed a memorandum of understanding (MOU) for a mine development agreement with the Martu (the local indigenous people) at our Kintyre project

We continued to advance our exploration activities, spending $10 million on five brownfield exploration projects, and $38 million for resource delineation at Kintyre and Cigar Lake. We spent about $48 million on regional exploration programs, mostly in Saskatchewan, followed by Australia, northern Canada, Asia and South America.

Updates on our other segments

In our fuel services segment, we decreased production due to unfavourable market conditions for UF₆.

In our electricity segment, Bruce Power Limited Partnership (BPLP) generated 24.9 terawatt hours (TWh) of electricity, at a capacity factor of 87%. Our share of earnings before taxes was $92 million.

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

Highlights		2011		2010		change
Uranium	Production volume (million lbs)		22.4		22.8		(2	)%
	Sales volume (million lbs)		32.9		29.6		11	%
	Revenue ($ millions)		1,616		1,358		19	%
	Gross profit ($ millions)		632		532		19	%
Fuel services	Production volume (million kgU)		14.7		15.4		(5	)%
	Sales volume (million kgU)		18.3		17.0		8	%
	Revenue ($ millions)		305		287		6	%
	Gross profit ($ millions)		54		65		(17	)%
Electricity	Output (100%) (TWh)		24.9		25.9		(4	)%
	Revenue (100%)		1,354		1,509		(10	)%
	Our share of earnings before taxes ($ millions)		92		172		(47	)%

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    5

Key market facts

Demand for electricity is expected to nearly double from 2009 to 2035, 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 2012, there were 431 operable commercial nuclear power reactors in 31 countries, providing about 13% of the world’s electricity.

• At the start of 2012, there were 63 reactors under construction, and by 2021 we expect 96 new reactors (net) to come on line.

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

• Over the next decade, we expect demand for uranium to grow by an average of 3% per year.

• To meet global demand over the next 10 years, we expect 65% of uranium supply will come from mines that are currently in operation, 15% from finite sources of secondary supply (mainly Russian highly enriched uranium (HEU), government inventories and limited recycling), and 20% will have to come from new sources of supply.

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

6    CAMECO CORPORATION

The nuclear fuel cycle

1 Mining

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.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    7

About Cameco

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

Management update

On July 1, 2011, Tim Gitzel assumed the role of president and chief executive officer (CEO), succeeding Jerry Grandey, who retired after more than eight years as CEO and 18 years with Cameco. Tim has developed extensive experience in Canadian and international uranium mining activities during his 18 years in senior management positions, and his transition to CEO was well planned and seamlessly executed. Tim joined the company in 2007 as senior vice-president and chief operating officer and was promoted to president in May of 2010. Before joining Cameco, he was executive vice-president, mining business unit for AREVA, based in Paris, France, with responsibility for uranium, gold, exploration and decommissioning operations in 11 countries around the world.

On July 15, 2011, Grant Isaac, previously senior vice-president, corporate services, became senior vice-president and chief financial officer (CFO), succeeding Kim Goheen who retired after 14 years with Cameco.

Alice Wong, previously vice-president, safety, health, environment, quality and regulatory relations, was appointed senior vice-president, corporate services.

Under Tim’s direction, the management team remains committed to the strategy, vision and values that have helped us become a global leader in the nuclear industry.

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. Our core strengths make us unique:

• a large portfolio of low-cost mining operations and geographically diverse uranium assets

• controlling interests in the world’s largest high-grade uranium reserves

• extensive mineral reserves and resources located near our existing infrastructure

• excellent growth potential from existing assets, combined with an advanced global exploration program

• multiple sources of conversion and the ability to adjust production in response to changing market signals

• a worldwide marketing presence and a strong, creditworthy customer base

• an extensive portfolio of long-term sales contracts supported by long-life assets

• innovative technology and experience operating in technically challenging environments

• a leader in corporate social responsibility—building long-term, trusting relationships with communities impacted by our operations

• an enterprise-wide risk management system tied directly to our strategy and objectives

• balanced financial management focused on adding value for our shareholders while positioning us for growth

• among the first to build relationships in emerging markets

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.

8    CAMECO CORPORATION

Business segments

Uranium

We are one of the world’s largest uranium producers, and in 2011 accounted for about 16% 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 (U₃O ₈)

Mineral reserves and resources

Mineral reserves

• approximately 435 million pounds proven and probable

Mineral resources

• approximately 254 million pounds measured and indicated and 318 million pounds inferred

Global exploration

• focused on four continents

• approximately 5 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

• McArthur River extension, Saskatchewan

• Kintyre, Australia

• Millennium, Saskatchewan

Fuel services

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

Products

• uranium trioxide (UO₃)

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

• uranium dioxide (UO₂) (the world’s only commercial supplier of natural UO₂)

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

Operations

• Blind River refinery, Ontario

(refines uranium concentrates to UO₃)

• Port Hope conversion facility, Ontario

(converts UO₃ to UF₆ or UO₂)

• Cameco Fuel Manufacturing Inc., Ontario

(manufactures fuel bundles and reactor components)

• a toll conversion agreement with Springfields Fuels Ltd.

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

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

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    9

Electricity

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

Capacity

• 3,260 megawatts (MW) (100% basis) (about 18% 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

Global presence

10    CAMECO CORPORATION

The nuclear energy industry today

The nuclear energy industry addressed significant challenges in 2011 related to events at the Fukushima-Daiichi nuclear power plant in Japan. As a result, the outlook for the industry remains uncertain for the near to medium term. In the long term, however, we continue to see a very strong and promising growth profile for the nuclear industry.

On March 11, an earthquake and tsunami in Japan caused cooling systems at the Fukushima-Daiichi nuclear power station to fail, and radioactive materials were released. This reduced public confidence in nuclear power in some countries, most notably Germany, which represents 5% of world nuclear generating capacity. It decided to revert to its previous phase-out policy, shutting down eight of its reactors, and plans to shut down the remaining nine reactors by 2022.

It remains unclear what level of nuclear power Japan itself—which represents 12% of global nuclear generating capacity—will depend on in the future. As of February 8, 2012, Japan had three reactors operating. These three reactors are scheduled to enter regular maintenance shutdowns between late February and the end of April, at which time we expect all of Japan’s nuclear reactors will be offline. Many are unaffected by the events in March 2011 but are offline for both planned and unplanned maintenance outages, and diminished public support has prevented utilities from gaining the regulatory and political approvals necessary to restart them. The Japanese government has ordered stress tests to be conducted on all reactors before allowing them to restart, and is implementing reforms to its existing nuclear regulatory framework and energy policy. Stress tests are progressing, but the government has not made any final decisions about restarting the reactors. Local government approval will also likely be required to allow reactors to restart.

The current operating status of reactors in Germany and Japan has caused concern that, in the near to medium term, additional volumes could be introduced to the market from deferrals and/or cancellations of deliveries under sales contracts. This has caused market participants to be discretionary in their purchases. We believe that utilities will continue to work with producers to manage these materials and minimize the impact on the market.

Cameco well positioned

During this period of uncertainty, we are in the enviable position of being heavily committed under long-term sales contracts through 2016. As well, we have commitments to supply a total of about 290 million pounds of uranium under all of our long-term contracts, many of which extend beyond 2016. Therefore, we expect to have a solid revenue stream for years to come, even in the event of declining uranium market prices.

Industry taking action

At the same time, the industry has taken action. Countries with nuclear programs are reviewing regulatory standards, assessing the safety of existing facilities and the design of reactors under construction or in the planning stage. Third party organizations such as the International Atomic Energy Association, Nuclear Energy Institute, World Association of Nuclear Operators, Institute of Nuclear Power Operators, and the World Nuclear Association are lending their support and technical expertise to governments and operators, and providing an accurate source of information for the public.

Preliminary safety reviews are now complete and lessons are being applied that we expect will make the industry even safer. Most countries with nuclear generation capacity have reconfirmed their commitment to the technology and to the future of nuclear energy.

Long-term outlook is positive

Electricity is essential to maintaining and improving the standard of living for people around the world. Demand for safe, clean, reliable, affordable energy continues to grow and the need for nuclear as part of the world’s energy mix remains compelling. We expect demand for uranium to grow, and along with it the need for new supply to meet future customer requirements. You can read more about our outlook on future supply and demand in The long-term view on page 14.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    11

Industry prices

Since March, the spot price has declined from $70 (US) per pound to the low $50 (US) per pound range. Utilities continue to be well covered under existing contracts. Given the current uncertainties in the market, we expect utilities and other market participants will continue to be cautiously opportunistic in their buying. We expect uranium demand in the near to medium term to remain somewhat discretionary, and so we expect prices to be relatively stable in 2012.

	2011		2010		change
Uranium ($US/lb) 1
Average spot market price		56.36		46.83		20	%
Average long-term price		66.79		60.92		10	%
Fuel services ($US/kgU UF6)1
Average spot market price
•   North America		10.61		9.11		16	%
•   Europe		10.61		9.83		8	%
Average long-term price
•   North America		16.09		12.21		32	%
•   Europe		16.42		13.27		24	%
Note: the industry does not publish UO2 prices.
Electricity ($/MWh)
Average Ontario electricity spot price		30		36		(17	)%

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

12    CAMECO CORPORATION

World consumption and production

While the events of 2011 reduced our estimate of global consumption in 2011 to 165 million pounds, which is about 15% lower than our original estimate of 195 million pounds, the industry also faced a number of production challenges this year. We estimate 2011 global production was 143 million pounds, about 5% below our original estimate of 150 million pounds.

We expect global uranium consumption to increase to about 175 million pounds in 2012, and global production to be approximately 150 million pounds. Secondary supplies should continue to bridge the gap.

By 2021, we expect world uranium consumption to be about 230 million pounds per year, an average annual growth rate of about 3%.

World consumption for UF₆ and natural UO₂ conversion services decreased 3% in 2011. After the events in Japan, a number of reactors were taken offline (primarily in Germany and Japan) and a number of new reactor startups were delayed as increased safety checks were required. We expect world consumption to increase by about 6% in 2012 as delayed new reactors come online.

Contract volumes

The Ux estimate for global spot market sales in 2011 is about 55 million pounds, 2% above the previous record high of 54 million pounds in 2009. Utilities were responsible for 34% of the purchases. Traders and financial players were the primary participants, taking advantage of the lower spot prices to make opportunistic purchases.

At the start of 2011, we expected long-term contracting volumes for the year to be between 150 million and 200 million pounds, but they ended the year at about 120 million pounds. We believe the decrease is likely related to utilities’ reluctance to contract during this period of market and price uncertainty. We estimate long-term contracting volumes in 2012 will be between 80 and 100 million pounds, depending on supply, market expectations and market prices.

2011 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 uncertainty. World population and industrial development continue to grow, and the World Energy Outlook for 2011 predicts a near doubling of electricity consumption between 2009 and 2035. Most of this energy will be used by developing (non-OECD) countries as their populations and standards of living increase.

New reactor outlook

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

This is evident in the growth in reactor construction we expect over the next 10 years. There are 431 reactors operable today. We expect the start up of 96 net new reactors by 2021, increasing the total number of operable reactors to 527.

This is a rate of growth in new reactor construction not seen since the 1970s.

14    CAMECO CORPORATION

Today there are 63 reactors under construction around the world. China continues to lead the growth, with 26 reactors under construction and dozens more planned. India, Russia and South Korea also continue to expand their nuclear generating capacity.

In the UK, government commitment to nuclear energy is strong, driven by concerns about energy security and the need to limit CO₂ emissions. The US continues to make progress toward new nuclear development with six units planned, four of which we expect will receive construction licences this year, and one of which is already under construction.

We have long-term supply contracts in many of these countries, including the US and China.

Other previously non-nuclear countries are either moving ahead with their reactor construction programs or considering adding nuclear to their energy programs in the future. For example, the United Arab Emirates is proceeding with its plans to have 5.6 gigawatts of nuclear capacity in place by 2020 and is beginning the process to secure fuel for those reactors. In Saudi Arabia, where power demand has been increasing by 7% to 8% annually, plans to build 16 reactors by 2030 have been announced. Vietnam, Poland, Lithuania, Turkey, Jordan, Egypt and Belarus are also moving forward with plans to proceed with nuclear power development.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    15

Demand for uranium is growing

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

We expect world demand of approximately 2.2 billion pounds over the next 10 years, which includes both world consumption and strategic inventory building. Although our previous forecast has decreased by about 7% due to the events in 2011, it is still significant growth. By 2021, we expect world uranium demand to be about 250 million pounds per year, an average annual growth rate of about 3%.

Supply is expected to tighten

While the impact of the March events in Japan on demand was more immediately apparent, the drop in uranium prices and ongoing global economic turmoil are beginning to have an impact on the outlook for supply.

Disruptions in mine production, difficulty raising funds for new mining projects, project delays, the announced cancellations of new mines or mine expansions, and the end of the Russian highly enriched uranium (HEU) commercial agreement, all point to tightening supply.

We expect 65% of global uranium supply over the next 10 years to come from existing primary production—mines that are currently in commercial operation—while we expect 15% to come from existing secondary supply sources. However, most secondary sources are finite and will not meet long-term needs. Currently, one of the largest sources of secondary supply is uranium derived from the Russian HEU commercial agreement. We expect all deliveries from this source to be made by the end of 2013, leaving a gap of about 24 million pounds per year. See Managing our supply and costs starting on page 23 for more information about the Russian HEU commercial agreement.

The result is that we expect 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. 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.

Cameco is well positioned

Given our extensive base of mineral reserves and resources, diversified sources of supply and global exploration program, we are well positioned to meet the growing demand for uranium.

16    CAMECO CORPORATION

Our strategy

Our strategy is to increase annual uranium production to 40 million pounds by 2018 and to invest in opportunities across the nuclear fuel cycle that we expect will complement and enhance our business.

Growth

Our growth strategy continues to focus on our uranium segment. Over the next 10 years, we expect 96 net new reactors to be built. Deliveries under the Russian HEU commercial agreement will end in 2013, and the industry will need new production. Lead-times in our industry are long, so we are preparing our assets today to make sure we can respond quickly to changing market conditions with a continued focus on profitability.

In addition, we have an active exploration program and a disciplined acquisition strategy, which we expect will provide us with opportunities to create synergies and grow.

Exploration

Our program is directed at replacing mineral reserves as they are depleted by our production, and ensuring our growth beyond 2018. We have maintained an active exploration 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. Many of these prospects are located close to our existing operations where we have established infrastructure and capacity to expand.

Our exploration efforts have increased uranium mineral reserves and resources at our operations. We have direct interests in almost 75 active exploration projects in eight countries, over 110 experienced professionals searching for the next generation of deposits, and ownership interests in approximately 5 million hectares (12.5 million acres) of land mainly in Canada, Australia, Kazakhstan, the US, Mongolia and Peru. In northern Saskatchewan alone, we have direct interests in 1.4 million hectares (3.5 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin. Many of our projects are advanced through joint ventures with both junior and major uranium companies.

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

Acquisition

We have a dedicated team looking for acquisition opportunities that we expect will further add to our production, 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.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    17

Uranium: growing production

We have a strategy and process in place to increase our annual production to 40 million pounds by 2018, which we expect to come from three sources:

• operating properties

• development projects

• projects under evaluation

We expect about half of the total 2018 annual production will come from mines that are already operating, while the other half is expected to come from projects that are in development or under evaluation.

We advance each project through a stage gate process that includes several defined decision points in the assessment and development stages. At each point, we re-evaluate the project based on current economic, competitive, social, legal, political and environmental considerations. If it continues to meet our criteria, we proceed to the next stage. This process allows us to build a pipeline of projects ready for a production decision.

The chart below shows the mix of projects we had when we started our Double U strategy in 2008 and how we expect each of these sources to progress towards achieving our 2018 production goal.

Many of these projects are in the early stage. Depending on the results of our evaluation activities or changing market signals, the mix of projects to reach our 2018 goal may change.

18    CAMECO CORPORATION

To meet our goal, we estimate our capital costs for the development projects and projects under evaluation in the chart will be between $200 and $400 million per year in growth capital for the next three years. See Capital spending starting on page 42.

This is a preliminary estimate that we expect to fund using existing cash balances and operating cash flows. Many of these are early stage projects, however, and the mix of projects and their underlying capital estimates could change significantly.

In 2008 Cameco launched a strategy to double our annual uranium production to 40 million pounds by 2018 (Double U).

We have been working toward that goal by focusing on our existing portfolio, monitoring the market and putting resources into the projects that make the most sense. We just completed year four of our 10-year strategy, and we are on track.

Operating properties

Our current sources of production are McArthur River/Key Lake, Rabbit Lake, Smith Ranch-Highland, Crow Butte and Inkai.

We plan to maintain production at these operations, and to expand production where we can by developing new mining zones. We are upgrading the mills at Key Lake and Rabbit Lake to support our plans for production growth.

Inkai blocks 1 and 2, in Kazakhstan, have the potential to significantly increase production. Based on current mineral reserves, we expect Rabbit Lake to produce until 2017, although work is ongoing to extend its mine life even further.

Development project

Cigar Lake is our project in development. It is a superior, world-class deposit that we expect to generate 9 million pounds of uranium per year (our share) after we finish construction and ramp up to full production. We are targeting first commissioning in ore in mid-2013, with the first pounds to be packaged at the McClean Lake mill in the fourth quarter of 2013.

Projects under evaluation

We are evaluating several potential sources of production, including expanding McArthur River, increasing production at Inkai blocks 1 and 2, advancing Inkai block 3, increasing production in the US, and advancing Kintyre and Millennium.

• The McArthur River extension is expected to expand our existing mining area, which is part of the most prolific high-grade uranium system in the world.

• Under an MOU with our Inkai partner, National Atomic Company KazAtomProm Joint Stock Company (Kazatomprom), we are in discussions to increase annual production from blocks 1 and 2 to 10.4 million pounds (100% basis).

• Inkai block 3, in Kazakhstan, has the potential to become a significant source of production.

• We are the largest producer in the US and are planning to almost double annual production.

• Our 70% interest in Kintyre, in Australia, adds potential to diversify our production by geography and deposit type.

• Millennium is a uranium deposit in northern Saskatchewan that we expect will take advantage of our excess milling capacity.

We expect to spend between $20 million and $25 million per year on average for the next three years to assess the feasibility of projects under evaluation. These amounts will be expensed as incurred.

You can read more about each of these projects in Our operations and development projects on page 61.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    19

Fuel services: capturing synergies

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

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

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

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

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

Enrichment has the potential to be a significant growth area for us, and offers operational synergies that could significantly enhance profit margins for both our uranium business and future enrichment operations. As one of the largest uranium suppliers in the world, our investment in this segment of the fuel cycle would help us capture additional value.

Electricity: capturing added value

Our investment in BPLP has been an excellent source of cash flow. Our focus is on maintaining steady cash flow and building synergies with our other segments. BPLP is considering extending the operating life of the four Bruce B units and we will have an opportunity to invest if BPLP decides to proceed. We would base this investment decision on the underlying value proposition and the strategic fit with our other growth objectives.

20    CAMECO CORPORATION

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

Assumptions

Our statements about increasing annual production by 2018 to 40 million pounds reflect our current production target for 2018. Although we are confident in our efforts to reach that target, we cannot guarantee that we will. We have made assumptions about 2018 production levels at each of our existing operating mines. We have also made assumptions about the development of mines that are not operating yet and their 2018 production levels. We believe these assumptions are reasonable, individually and together, but if an assumption about one or more mines proves to be incorrect, we will not reach our 2018 target production level unless the shortfall can be made up by additional production at another mine.

Material risks that could prevent us from reaching our target

• we cannot locate additional mineral reserves and identify appropriate methods of mining to maintain and increase production levels at McArthur River

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

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

• we cannot bring block 3 into production at Inkai if the feasibility study is not favourable or we cannot secure partner or government approval

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

• development of Kintyre is delayed due to political, regulatory or indigenous people issues

• we cannot obtain a favourable feasibility study for Kintyre or the Millennium project, or we cannot reach agreement with our project partners to move ahead with production at Kintyre or Millennium

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

• the projects under evaluation do not proceed or, if they do, are not completed on schedule or do not reach full production levels as quickly as we expect

• uranium prices and development and operating costs make it uneconomical to develop projects under consideration

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

• disruption in production or development due to natural phenomena, labour disputes, political risks, blockades or other acts of social or political activism, lack of tailings capacity, or other development and operation risks

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    21

Building on our strengths

World-class assets

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

Employee expertise

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

Strong customer relationships

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

Uranium price leverage

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

Financial strength

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

Disciplined portfolio management

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

Focused risk management

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

Innovation

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

Reputation

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

22    CAMECO CORPORATION

Managing our growth

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

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

• outstanding financial performance

• a safe, healthy and rewarding workplace

• a clean environment

• supportive communities

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

Focus on long-term sustainability

Companies are under growing scrutiny for the way they conduct their businesses, 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 sustainable development report and annual information form, which are on our website (cameco.com).

Outstanding financial performance

The mining industry is becoming increasingly competitive, particularly in two of the jurisdictions where we operate, northern Saskatchewan in Canada and Western Australia. Our financial results depend heavily on our sales and production volumes, on the cost of supply, and on the prices we realize in our uranium and fuel services segments.

Managing our supply and costs

We sell more uranium than we produce every year. We meet our delivery commitments using uranium we obtain:

• from our own production

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

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

Like all mining companies, our uranium segment is affected by the rising cost of inputs like labour and fuel. In 2011, labour, production supplies and contracted services made up 88% of the production costs at our uranium mines. Labour (34%) was the largest component. Production supplies (27%) included fuels, reagents and other items. Contracted services (27%) included mining and maintenance contractors, air charters, security and ground freight.

Operating costs in our fuel services segment are mainly fixed. In 2011, labour accounted for about 49% of the total. The largest variable operating cost is for energy (natural gas and electricity), followed by zirconium and anhydrous hydrogen fluoride.

To help us operate efficiently and cost-effectively as we grow, we manage operating costs and improve plant reliability by prudently investing in production infrastructure, new technology and business process improvements.

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

Our long-term purchase contracts are at fixed prices that are lower than the current published spot and long-term prices. Our most significant long-term purchase contract is the Russian HEU commercial agreement, which ends in 2013. We expect to purchase about 17 million pounds, our remaining volumes, under this agreement to the end of 2013. The purchase price escalates with inflation and was agreed to in 2001 when uranium prices were much lower than today. In 2008, pricing on approximately 6 million pounds of the remaining volumes available to us in 2012 and

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    23

2013 was renegotiated. Using a $60 (US) per pound uranium spot price, the average price increase from 2012 to 2013 on these 6 million pounds is expected to be about $18 (US) per pound (including an adjustment for inflation).

After the Russian HEU commercial agreement ends in 2013, we expect to maintain our sales volumes using a combination of sources including:

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

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

• discretionary use of inventories

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

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

Managing contracts

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

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

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

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

Our current uranium contracting strategy is to sign contracts with terms of 10 years or more that include mechanisms to protect us when market prices decline, and allow us to benefit when market prices go up. Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. Fixed-price contracts are typically based on the industry long-term price indicator at the time the contract is accepted, adjusted for inflation to the time of delivery. Market-related contracts may be based on either the spot price or the long-term price as quoted at the time of delivery, and often include floor prices adjusted for inflation and some include ceiling prices also adjusted for inflation.

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

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

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

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

24    CAMECO CORPORATION

A safe, healthy and rewarding workplace

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

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

Our approach is working. We were recognized in a number of ways for our employee programs in 2011: the Financial Post named Cameco one of the Top 10 Best Companies to Work For in Canada; Mediacorp named us one of Canada’s Top 100 Employers; and The Globe and Mail named us one of Canada’s Top Diversity Employers. You can find out more about our awards on cameco.com.

A clean environment

We are committed to operating our business with respect and care for the local and global environment. We strive to be a leader in environmental practices and performance by complying with and moving beyond legal and other requirements.

We are committed to integrating environmental leadership into everything we do. In 2005, we launched a formal environmental leadership initiative, and set objectives and performance indicators to measure our progress in protecting the air, water and land near our operations, and in reducing the amount of waste we generate and energy we use.

Reducing our impact

We have been working to reduce the impact we have on the environment. This includes monitoring and reducing our effect on air, water and land, reducing the greenhouse gases we produce and 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 this continues to improve our safety and environmental performance and operating efficiency.

We have developed new water treatment technologies that have improved the quality of the water released from our Saskatchewan uranium milling operations, and are working on other projects to reduce waste, improve the reclamation process and manage waste rock more effectively.

We have also completed an energy assessment at each of our North American operations, and developed management plans for reducing our energy intensity and greenhouse gas emissions.

We are maximizing the lifespan of our operating sites to limit the environmental impact of operations, and revitalizing the Key Lake mill (in operation for 29 years) and Rabbit Lake mill (in operation for 37 years).

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. 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.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    25

Supportive communities

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

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

For example, in northern Saskatchewan in 2011:

• just over 50% of the employees at our northern mines were local residents (more than 760 residents) and were paid over $43 million in wages

• approximately $390 million was paid to northern businesses, who provided 74% of services to our northern minesites. This is the most that we have ever procured from northern vendors in one year.

• we made nearly 90 community visits in northern Saskatchewan to discuss potential projects at our northern operations and to provide career information to high school students and community members

• we donated over $1.3 million to northern and aboriginal initiatives for youth, health and wellness, education and literacy, and culture and recreation

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

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

Our objectives are consistent with those of our regulators—to keep people safe and to protect the environment. We pursue these goals through open and co-operative relationships with all of our regulators. We work to earn their trust and that of other stakeholders by continually striving to protect people and the environment.

26    CAMECO CORPORATION

Measuring our results

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.

2011 objectives	Results	2012 objectives This is forward-looking information. See page 2 for more information.
Outstanding financial performance
Production •       Produce 21.9 million pounds of U3O8 and between 15 million and 16 million kgU from fuel services.	Achieved •       Our share of U3O8 production was 22.4 million pounds, or 102% of plan, and we produced 14.7 million kgU at fuel services, or 98% of plan. Exceeded •       Exceeded our production target of 18.7 million lbs U3O8 (100% basis) by 7% at McArthur River/Key Lake through technological advancements and identification of mining opportunities that allowed us to take advantage of production flexibility provisions in our operating licences.	Production •       Achieve budgeted production from our uranium and fuel services segments. McArthur River •       Implement productivity improvements to maintain planned production during mining zone transitions.
Financial measures Corporate performance •       Achieve budgeted net earnings and cash flow from operations (before working capital changes).	Exceeded •       Adjusted net earnings1 were $509 million, 32% higher than budget. Cash flow from operations (before working capital changes)1 was $850 million, 41% higher than budget.	Financial measures Corporate performance •       Achieve budgeted adjusted net earnings and cash flow from operations (before working capital changes).
Costs •       Strive for unit costs below budget.	Achieved •       Actual unit operating costs for uranium were 1% better than budgeted costs of $19.19 per lb U3O8 produced and exceeded budgeted unit production costs for fuel services of $15.65 per kgU sold, by 3%. The results were weighted 70/30, reflecting the portion each segment makes up of our business. Our minimum target was to achieve budgeted unit costs on a consolidated basis. Target was achieved in the face of cost escalation fueled by increased resource development activity where we operate.	Costs •       Achieve budgeted unit costs.

¹  We use adjusted net earnings and cash flow from operations (before working capital changes) as a more meaningful way to compare our financial performance from period to period. These are not standard measures, and not a substitute for financial information prepared in accordance with IFRS. Other companies may calculate these measures differently. See Adjusted net earnings (non-IFRS/GAAP measure) and note 26 to our audited 2011 financial statements for more information.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    27

2011 objectives	Results	2012 objectives
Outstanding financial performance
Growth Cigar Lake •       Advance the project towards mid-2013 startup by completing remediation of all underground workings and advancing shaft 2 sinking. Inkai •       Advance block 3 mineral resource delineation and the engineering design of a test leach facility. Advance construction of site infrastructure.	Achieved •       Completed remediation of all underground workings and completed sinking of shaft 2 to the 480 metre level. Cigar Lake is a challenging deposit to mine. Completion of these critical milestones required careful planning and deliberate execution. Partially achieved •       Advanced block 3 mineral resource delineation, completed engineering for a test leach facility and began infrastructure development. We need regulatory approval of the detailed delineation and test leach work programs. The approval process has been challenging because of the complex and developing regulatory environment. Partially achieved	Growth •       Meet regulatory project milestones and stage gate assessments on projects that support our Double U strategy. Cigar Lake •       Advance the project towards startup in 2013 by successfully completing critical activities planned for 2012. Inkai •       Advance block 3 mineral resource delineation drilling and complete the test leach facility. •       Receive approval to increase annual production from blocks 1 and 2 to design capacity of 5.2 million pounds per annum (100% basis). Continue to advance our longer-term objective of receiving approval to double annual production from blocks 1 and 2, extend the lease terms and secure block 3 mining rights.
•       Receive approval to increase annual production from blocks 1 and 2 to design capacity of 5.2 million pounds per annum (100% basis). Pursue our longer-term objective of receiving approval to double annual production from blocks 1 and 2 by advancing the conversion joint venture project with Kazatomprom.	•       Signed memorandum of agreement with our partner to increase annual production from blocks 1 and 2 to 5.2 million pounds per year (100% basis). Government approval is pending in this complex and developing regulatory environment. To pursue our longer-term objective to double annual production, we continued to explore with Kazatomprom the feasibility of building a uranium conversion facility and other potential collaborations in uranium conversion.

28    CAMECO CORPORATION

2011 objectives	Results	2012 objectives
Outstanding financial performance
Growth (continued) Kintyre •       Continue to advance project evaluation to allow a production decision as soon as possible.	Partially achieved •       Significantly advanced a prefeasibility study and an environmental review and management program in a remote area that is often subject to extreme weather conditions. To support our prefeasibility study, we expanded the scope of our drilling program and delayed these activities to 2012. Gained support in principle from the Martu, the local indigenous people, for development of the project.	Growth (continued) Kintyre •       Continue to advance project evaluation in 2012 and decide if we will proceed to feasibility. Exploration and innovation •       Replace mineral reserves and resources at the rate of annual U3O8 production based on a three-year rolling average.
Millennium •       Continue to advance the Millennium project toward a project decision.	Achieved •       Continued to work on the environmental assessment and carried out additional studies and design work. Our 2011 drill program resulted in an increase in inferred resources. As a project under evaluation, it must pass a number of decision points before the project decision is made.
Exploration and innovation •       Replace mineral reserves and resources at the rate of annual U3O8 production based on a three-year rolling average.	Achieved •       Over the last three years, mineral reserves decreased by 60 million pounds compared to production of 66 million pounds, measured and indicated resources increased by 126 million pounds and inferred resources decreased by 18 million pounds. On average, production was replaced and exceeded by 16 million pounds per year in each of the last three years (2009 to 2011). Replacing our reserves and resources is fundamental to our long-term success. Achieved
•       Support production growth and improved operating efficiencies through targeted research, development and technological innovation.	•       Advanced numerous ongoing research projects and selected four of these to fast track that are aimed at improving our environmental performance and process efficiencies at our operations. Innovation is critical to achieving continuous improvement in these areas even though it is complex and its outcome is uncertain.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    29

2011 objectives	Results	2012 objectives
Outstanding financial performance
Growth (continued) McArthur River extension •       Advance the underground exploration drifts to the north of current mining areas and initiate a feasibility study.	Achieved •       Advanced the underground exploration drifts based on our updated mine plan and began feasibility work. Upgraded resources from inferred to indicated based on surface drilling. Achieved these results while managing the operational risks associated with the location and grade of the orebody.	Growth (continued)
Management •       Sustain and grow production in accordance with our strategy to double annual uranium production by 2018 by advancing pipeline uranium projects through the stage gate process.	Achieved •       Successfully implemented the stage gate process and incorporated all of our global development projects into the process. This is a complex scheduling process involving cross-functional teams, communication across different disciplines and several large capital projects in different geographic locations competing for internal resources.	Management •       Deliver capital projects planned for completion in 2012 within budget and on schedule.
•       Deliver planned capital projects within 10% of budget.	Achieved •       The 213 capital projects that closed in 2011 were 3.8% below our budget of $150 million.
Safe, healthy and rewarding workplace
•       Strive for no lost-time injuries at all Cameco-operated sites and, at a minimum, maintain a long-term downward trend in combined employee and contractor injury frequency and severity, and radiation doses.	Achieved •       Safety performance in 2011 was strong overall, although performance declined slightly from last year’s record-setting level and there were a few serious near misses. Lost-time incident frequency for employees and contractors was 0.3 per 200,000 hours worked compared to a target of 0.4, severity was 8.9 compared to a target of 25.	•       Strive for no lost-time injuries at all Cameco-operated sites and, at a minimum, maintain a long-term downward trend in combined employee and contractor injury frequency and severity, and radiation doses. •       Attract, retain, engage and develop employees in support of current and future operations and establish succession pools for key positions.
•       Complete implementation of the risk standard and integrate it into our quality management system. Adopt a risk policy and implement improvements to the risk governance structure at the management and board level.	Achieved •       Completed implementation of the risk standard and integrated it into our quality management system. This involved significant change management across Cameco. Management and the board approved the risk policy, and we made improvements to our risk governance structure.

30    CAMECO CORPORATION

2011 objectives	Results	2012 objectives
Clean environment
•       Strive for zero reportable environmental incidents, reduce the frequency of incidents and have no significant incidents at Cameco-operated sites.	Partially achieved •       There were 31 reportable environmental incidents, slightly above our three-year average of 29, but within the range of expected statistical variation. There were no significant environmental incidents.	•       Strive for zero reportable environmental incidents, reduce the frequency of incidents and have no significant incidents at Cameco-operated sites.
•       Improve year-over-year performance in corporate environmental leadership indicators.	Achieved •       Two of eight key performance indicators showed an improvement over 2010, while two were at the same level as 2010. Higher rates in two of the key indicators were largely influenced by the cleanup of historic waste. Higher rates in the remaining two key indicators were tied to increased activity at our operations. We need continuous innovation in our practices and technology to improve year-over-year.
Supportive communities
•       Develop long-term relationships by engaging with stakeholders important to our sustainability. Ensure support from our employees, impacted communities, investors, governments and the general public through communications, community investment and business development.	Achieved •       Established and maintained positive relationships with groups affected by our operating activities. Received a higher management credibility rating of 74% in our investor perception study compared to 64% in 2010. Maintained strong corporate trust ratings in Saskatchewan (7.24/10 compared to 7.62 in 2010), Port Hope (7.98/10 compared to 7.58 in 2010) and the US (7.32/10 compared to 7.74 in 2010). These levels of support for our operations were achieved in the face of inherent challenges for mining companies, complicated by misperceptions of the nuclear industry. Named a Top 100 Employer and among the 10 Best Companies to Work For, and received awards for being one of Saskatchewan’s Top Employers, Canada’s Best Diversity Employers and a Top Employer of Canadians Over 40.	•       Develop long-term relationships by engaging with regulators and other stakeholders important to our sustainability. Secure continued support from our employees, impacted communities, investors, governments and the general public through communications, community investment and business development. •       Implement Cameco’s corporate social responsibility policy to advance Cameco projects in all locations and secure support from indigenous communities affected by our operations.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    31

Financial results

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

2011 consolidated financial results	33
Outlook for 2012	39
Liquidity and capital resources	40
2011 financial results by segment	46
Uranium	46
Fuel services	50
Electricity	51
Fourth quarter results	53
Fourth quarter consolidated results	53
Quarterly trends	54
Fourth quarter results by segment	55

32    CAMECO CORPORATION

2011 consolidated financial results

On January 1, 2011, we adopted IFRS for Canadian publicly accountable enterprises. Our financial statements have been prepared using IFRS. Amounts relating to the year ended December 31, 2010 in this MD&A and our related financial statements have been revised using IFRS for comparative purposes. Amounts for periods prior to January 1, 2010 are presented in accordance with Canadian GAAP.

Highlights December 31 ($ millions except per share amounts)	2011		2010		Canadian GAAP 2009			change from 2010 to  2011
Revenue		2,384		2,124		2,315			12	%
Gross profit		776		771		750			1	%
Net earnings		450		516		1,099	1		(13	)%
$ per common share (basic)		1.14		1.31		2.83	1		(13	)%
$ per common share (diluted)		1.14		1.31		2.82	1		(13	)%
Adjusted net earnings (non-IFRS/GAAP, see below)		509		497		528			2	%
$ per common share (adjusted and diluted)		1.29		1.26		1.35			2	%
Cash provided by operations (after working capital changes)		732		521		690			40	%

¹ Net earnings for 2009 includes an amount of $382 million relating to a discontinued operation. In 2009, we sold our interest in Centerra Gold Inc. For that year, net earnings from continuing operations amounted to $717 million ($1.84 per share basic & diluted).

Net earnings

Our net earnings were $450 million ($1.14 per share diluted) compared to $516 million ($1.31 per share diluted) in 2010 mainly due to:

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

• higher taxes due to an increase in the provision related to our transfer pricing dispute with the Canadian Revenue Agency (CRA)

• lower earnings from our fuel services business as a result of an increase in the cost of sales, partially offset by an increase in sales volumes

• losses on foreign exchange derivatives, compared to gains in 2010

• higher earnings from our uranium business due to higher realized prices, and an increase in sales volumes, partially offset by an increase in the cost of sales

Three-year trend

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

In 2010, our net earnings were $583 million lower than in 2009 primarily due to us selling our interest in Centerra and recording an after tax gain of $374 million in 2009. We also recorded an after tax profit of $189 million on foreign exchange derivatives in 2009 compared to an after tax profit of $19 million in 2010.

Adjusted net earnings (non-IFRS/GAAP measure)

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 earnings from discontinued operations. We also used this measure prior to adoption of IFRS (non-GAAP measure).

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    33

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 2011 and 2010 as reported in our financial statements.

($ millions)	2011			2010			Canadian GAAP 2009
Net earnings		450			516			1,099
Adjustments
Earnings from discontinued operations (after tax)		—			—			(382	)
Adjustments on derivatives1 (pre-tax)		80			(26	)		(257	)
Income taxes on adjustments to derivatives		(21	)		7			68
Adjusted net earnings		509			497			528

¹  In 2008, we opted to discontinue hedge accounting for our portfolio of foreign currency forward sales contracts. Since then, we have adjusted our gains or losses on derivatives as reported under IFRS (and previously under Canadian GAAP) to reflect what our earnings would have been had hedge accounting been applied.

The table below shows what contributed to the change in adjusted net earnings for 2011.

($ millions)
Adjusted net earnings – 2010		497
Change in gross profit by segment (we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits)
Uranium	Higher sales volume	58
	Higher realized prices ($US)	182
	Foreign exchange impact on realized prices	(71	)
	Higher costs	(68	)
	Hedging benefits	20
	change – uranium	121
Fuel services	Higher sales volume	5
	Lower realized prices ($Cdn)	(3	)
	Higher costs	(13	)
	Hedging benefits	3
	change – fuel services	(8	)
Electricity	Lower sales volume	(8	)
	Lower realized prices ($Cdn)	(30	)
	Higher costs	(46	)
	change – electricity	(84	)
Other changes
Cigar lake remediation		12
Income taxes		(36	)
Other		7
Adjusted net earnings – 2011		509

34    CAMECO CORPORATION

Three-year trend

Our adjusted net earnings have been relatively stable over the past three years.

The 6% decrease from 2009 to 2010 resulted from:

• lower profits from our electricity business, relating to a lower realized selling price

• higher exploration expenses

• higher income taxes

• partially offset by improved profits in the uranium business, relating to the lower cost of sales

The 2% increase from 2010 to 2011 resulted from:

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

• an increase in the cost of sales

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

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

• higher income taxes

Revenue

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

($ millions)
Revenue – 2010	2,124
Uranium
Higher sales volume	147
Higher realized prices ($Cdn)	111
Fuel services
Higher sales volume	21
Lower realized prices ($Cdn)	(3	)
Electricity
Lower output	(19	)
Lower realized prices ($Cdn)	(31	)
Other	34
Revenue – 2011	2,384

See Financial results by segment on page 46 for more detailed discussion.

Three-year trend

In 2010, revenue declined by 8% to $2.1 billion largely due to reduced sales volumes in the uranium business and a lower realized price in electricity. The decline in sales volumes was matched with an increase in inventories.

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

Average realized prices

		2011		2010		2009		change from 2010 to  2011
Uranium1	$US/lb $Cdn/lb		49.17 49.18		43.63 45.81		38.25 45.12		13 7	%  %
Fuel services	$Cdn/kgU		16.71		16.86		17.84		(1	)%
Electricity	$Cdn/MWh		54		58		64		(7	)%

¹  Average realized foreign exchange rate ($US/$Cdn): 2011 – $1.00, 2010 – $1.05 and 2009 – $1.18.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    35

Outlook for 2012

We expect consolidated revenue to be 0% to 5% lower in 2012 due to:

• lower sales volumes in the fuel services business

• decrease in realized prices in the uranium business

• partially offset by higher volumes in the electricity business

Our customers choose when in the year to receive deliveries of uranium and fuel services products, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly. We expect that deliveries this year will be evenly distributed across the quarters. However, not all delivery notices have been received to date, which could alter the delivery pattern.

Corporate expenses

Administration

($ millions)	2011		2010		change
Direct administration		147		145		1	%
Stock-based compensation		10		10		—
Total administration		157		155		1	%

Direct administration costs in 2011 were $2 million higher than in 2010 as we continued to pursue and evaluate growth opportunities. These costs were lower than we forecast as we narrowed the scope of some business development activities during the year.

We recorded $10 million in stock-based compensation expenses this year under our stock option, deferred share unit, performance share unit and phantom stock option plans, the same as in 2010. See note 27 to the financial statements.

Outlook for 2012

We expect administration costs (not including stock-based compensation) to be about 10% to 15% higher than in 2011 due to planned higher spending in support of our growth strategy.

Exploration

In 2011, uranium exploration expenses were $96 million, the same as in 2010. Our exploration efforts in 2011 focused on Canada, Australia, Kazakhstan and the United States.

Outlook for 2012

We expect exploration expenses to be about 15% to 20% higher than they were in 2011 due to an increase in evaluation activities at Kintyre and Inkai block 3. We will also continue to focus efforts in Canada.

Finance costs

Finance costs were $74 million compared to $86 million in 2010. The decrease from last year largely reflects lower foreign exchange expenses and product loan standby fees. The product loan facility was terminated in 2010. See note 22 to the financial statements.

Finance income

Finance income was $25 million compared to $21 million in 2010 due to higher rates of return on short-term investments.

36    CAMECO CORPORATION

Gains and losses on derivatives

In 2011, we recorded $4 million in losses on our derivatives compared to gains of $75 million in 2010. The losses reflect the weakening of the Canadian dollar in 2011. See note 29 to the financial statements.

Income taxes

We recorded an income tax expense of $12 million in 2011 compared to $3 million in 2010 and higher than the guidance we provided in our third quarter MD&A (0% to 5% recovery). The higher expense was primarily due to an increase in the provision related to the CRA transfer pricing dispute discussed below. The increase in the provision was partially offset by higher losses being incurred in Canada, which was largely attributable to losses we recorded on derivatives in 2011 compared to the gains recorded in 2010. See note 24 to the financial statements.

On an adjusted earnings basis, our tax expense was $33 million in 2011 compared to a recovery of $3 million in 2010. The increase was primarily due to the increase in the provision related to the CRA transfer pricing dispute. Our effective tax rate was 6% in 2011 compared to a recovery of 1% in 2010. The table below presents our adjusted earnings and adjusted income tax expenses attributable to Canadian and foreign jurisdictions.

($ millions)	2011			2010
Pre-tax Adjusted Earnings1
Canada2		(297	)		(89	)
Foreign		827			573
Total pre-tax adjusted earnings		530			484
Adjusted Income Taxes1
Canada2		(34	)		(46	)
Foreign		67			43
Adjusted income tax expense (recovery)		33			(3	)
Effective tax rate		6	%		(1	)%

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/GAAP measure on pages 33 & 34).

Since 2008, CRA has disputed the transfer pricing methodology we used for certain uranium sale and purchase agreements and issued notices of reassessment for our 2003 through 2006 tax returns. We believe it is likely that CRA will reassess our tax returns for 2007 through 2011 on a similar basis. Our view is that CRA is incorrect, and we are contesting its position. As a result we are pursuing our appeal rights under the Income Tax Act. However, to reflect the uncertainties of CRA’s appeals process and litigation, we have provided a total of $54 million for uncertain tax positions for the years 2003 through 2011. We believe that the ultimate resolution of this matter will not be material to our financial position, results of operations or liquidity over the period. However, an unfavourable outcome for the years 2003 to 2011 could be material to our financial position, results of operations or cash flows in the year(s) of resolution. See note 24 to the financial statements.

Outlook for 2012

On an adjusted net earnings basis, we expect our effective income tax rate will reflect a net recovery of 0% to 5% as taxable income in Canada is expected to decline. For the next few years, we expect our tax rate to continue in accordance with our 2012 outlook.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    37

Foreign exchange

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

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

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

At December 31, 2011:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.02(Cdn), up from $1.00 (US) for $0.99 (Cdn) at December 31, 2010. The exchange rate averaged $1.00 (US) for $0.99 (Cdn) over the year.

• Our effective exchange rate for the year was about $1.00 (US) for $1.00 (Cdn), compared to $1.00 (US) for $1.05 (Cdn) in 2010.

• We had foreign currency contracts of $1.4 billion (US) and EUR 31 million at December 31, 2011. The US currency contracts had an average exchange rate of $1.00 (US) for $1.01 (Cdn).

• The mark-to-market loss on all foreign exchange contracts was $18 million compared to a $47 million gain at December 31, 2010.

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2011, 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, 2011, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2011 net earnings by about $10 million (Cdn). This sensitivity is based on an exchange rate of $1.00 (US) for $1.02 (Cdn).

38    CAMECO CORPORATION

Outlook for 2012

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

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

Our outlook for 2012 reflects the growth expenditures necessary to help us achieve our strategy. We do not provide an outlook for the items in the table that are marked with a dash.

See Financial results by segment on page 46 for details.

2012 Financial outlook

	Consolidated	Uranium	Fuel services	Electricity
Production	—	21.7 million lbs	13 to 14 million kgU	—
Sales volume	—	31 to 33 million lbs	Decrease 10% to 15%	—
Capacity factor	—	—	—	95%
Revenue compared to 2011	Decrease 0% to 5%	Decrease 0% to 5%1	Decrease 10% to 15%	Increase 5% to 10%
Average unit cost of sales (including D&A)	—	Increase 0% to 5%2	Increase 10% to 15%	Decrease 5% to 10%
Direct administration costs compared to 20113	Increase 10% to 15%	—	—	—
Exploration costs compared to 2011	—	Increase 15% to 20%	—	—
Tax rate	Recovery of 0% to 5%	—	—	—
Capital expenditures	$620 million4	—	—	$80 million

¹  Based on a uranium spot price of $52.00 (US) per pound (the Ux spot price as of February 6, 2012), a long-term price indicator of $61.00 (US) per pound (the Ux long-term indicator on January 30, 2012) and an exchange rate of $1.00 (US) for $1.00 (Cdn).

²  This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we decide to make discretionary purchases in 2012 then we expect the average unit cost of sales to increase further.

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

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

Sensitivity analysis

For 2012:

• a change of $5 (US) per pound in each of the Ux spot price ($52.00 (US) per pound on February 6, 2012) and the Ux long-term price indicator ($61.00 (US) per pound on January 30, 2012) would change revenue by $68 million and net earnings by $55 million.

• a change of $5/MWh in the electricity spot price would change our 2012 net earnings by $4 million based on the assumption that the spot price will remain below the floor price of $50.18/MWh provided for under BPLP’s agreement with the Ontario Power Authority (OPA).

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    39

Liquidity and capital resources

At the end of 2011, we had cash and short-term investments of $1.2 billion in a mix of short-term deposits and treasury bills, while our total debt amounted to $1.0 billion. We were in a similar position at the end of 2010.

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.

Our financial objective is to make sure we have the cash and debt capacity to fund our operating activities, investments and growth. We have several alternatives to fund future capital needs, including our significant cash position, credit facilities, future operating cash flow and debt or equity financing, and are continually evaluating these options to make sure we have the best mix of capital resources to meet our needs.

Financial condition

	2011			2010
Cash position ($ millions) (cash, cash equivalents, short-term investments)		1,203			1,260
Cash provided by operations ($ millions) (net cash flow generated by our operating activities after changes in working capital)		732			521
Cash provided by operations/net debt (net debt is total consolidated debt, less cash and cash equivalents)		n/a	1		n/a	1
Net debt/total capitalization (total capitalization is total long-term debt and equity)		n/a	1		n/a	1

¹  Cash and cash equivalents exceeded debt.

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, 2011:

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.

40    CAMECO CORPORATION

Liquidity

($ millions)	2011			2010
Cash and cash equivalents at beginning of year		1,260			1,304
Cash from operations		732			521
Investment activities
Additions to property, plant and equipment		(647	)		(431	)
Other investing activities		40			12
Financing activities
Change in debt		(3	)		(10	)
Interest paid		(61	)		(54	)
Issue of shares		7			18
Dividends		(146	)		(106	)
Other financing activities		13			10
Exchange rate on changes on foreign currency cash balances		8			(4	)
Cash and short-term investments at end of year		1,203			1,260

On transition to IFRS, we elected to classify interest payments as a financing activity rather than an operating activity in our statement of cash flows. This change will increase our reported cash flows from operating activities with a corresponding decrease in cash flows from financing activities. There is no net impact on consolidated cash flows as a result of this change in presentation. Prior period amounts for 2010 have been revised to reflect this classification.

Cash from operations

Cash from operations was 40% higher than in 2010 mainly due to higher profits in the uranium business and lower working capital requirements relating to decreased inventory levels. Not including working capital requirements, our operating cash flows in the year were up $60 million. See note 26 to the financial statements.

Investing activities

Cash used in investing includes acquisitions and capital spending.

Acquisitions and divestitures

In 2010 and 2011, we concluded no significant acquisitions or divestitures.

Talvivaara Agreement

On February 7, 2011, we signed two agreements with Talvivaara Mining Company Plc (Talvivaara) to buy uranium produced at the Sotkamo nickel-zinc mine in eastern Finland. Under the first agreement with Talvivaara, we will provide an up-front payment, to a maximum of $60 million (US), to cover certain construction costs. 2011 expenditures were $19 million (US) and we expect to fund an additional $41 million (US) in 2012. This amount will be repaid through the initial deliveries of uranium concentrates. Once the full amount has been repaid, we will continue to purchase the uranium concentrates produced at the Sotkamo mine through a second agreement, which provides for the purchase of uranium using a pricing formula that references market prices at the time of delivery. The second agreement expires on December 31, 2027.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    41

Capital spending

We classify capital spending as growth or sustaining. Growth capital is money we invest to generate incremental production, and for business development. Sustaining capital is the money we spend to keep our operations at current production levels.

(Cameco’s share in $ millions)	2011 plan			2011 actual		2012 plan
Growth capital
Cigar Lake		176			172		215
Inkai		9			1		10
McArthur River		14			24		35
Millennium		6			4		5
US ISR		13			15		30
Total growth capital		218			216		295
Sustaining capital
McArthur River/Key Lake		169			168		145
US ISR		38			39		50
Rabbit Lake		85			77		75
Inkai		19			15		30
Fuel services		32			18		20
Other		14			20		5
Total sustaining capital		357			337		325
Total uranium & fuel services		575	1		553		620
Electricity (our 31.6% share of BPLP)		80			77		80

¹ We updated our 2011 capital cost estimate in the Q1 MD&A to $620 million, in the Q2 MD&A to $590 million and in the Q3 MD&A to $575 million.

Capital expenditures were 4% below the guidance we provided in our third quarter MD&A, mainly due to variances at Inkai and in the fuel services division. We do not expect this reduction in capital expenditures in 2011 will impact our plans to increase annual uranium production by 2018. The variance at fuel services was mainly due to cancellation of certain projects and revisions to project schedules. The variance at Inkai was mainly due to the deferral of upgrades to infrastructure and slower than expected progress on approvals for block 3.

Outlook for investing activities

We expect total capital expenditures for uranium and fuel services to be about 12% higher in 2012 as a result of higher spending for:

• growth capital at Cigar Lake

• growth and sustaining capital at US ISR

• sustaining capital at Inkai

Major sustaining expenditures in 2012 include:

• McArthur River/Key Lake – At McArthur River, the largest component is mine development at about $50 million. Other projects include site facility expansion and equipment purchases. At Key Lake, various projects to revitalize the mill will be undertaken at about $35 million, as well as work on the tailings facilities.

• US in situ recovery (ISR) – Wellfield construction and well installation is the largest project at approximately $30 million. We also plan to work on the development of the Gas Hills and North Butte projects as well as revitalization of the Highland processing plant.

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

42    CAMECO CORPORATION

In addition, we expect capital expenditures for 2013 and 2014 to be as follows:

($ millions)	2013		2014
Growth capital		325 – 350		250 – 275
Sustaining capital		325 – 350		350 – 375
Total uranium & fuel services		650 – 700		600 – 650

These growth capital expenditures are related to our Double U strategy. Many of these are early stage projects, however, and the mix of projects and their underlying capital estimates could change significantly. This is a preliminary estimate that we expect to fund using existing cash balances and operating cash flows.

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 page 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.

As a result of our significant cash balance, there was little in the way of financing activities in 2011.

Long-term contractual obligations

December 31, 2011 ($ millions)	2012		2013 and 2014		2015 and 2016		2017 and beyond		Total
Long-term debt		15		41		342		549		947
Interest on long-term debt		53		102		78		80		313
Provision for reclamation		10		40		47		480		577
Provision for waste disposal		4		7		11		—		22
Other liabilities		—		—		—		507		507
Total		82		190		478		1,616		2,366

In the fourth quarter, we cancelled our $100 million revolving credit facility that was maturing in February 2012. We also amended and extended our $500 million unsecured revolving credit facility that was maturing in November 2012. We now have unsecured lines of credit of about $1.9 billion, which include the following:

• A $1.25 billion unsecured revolving credit facility that matures November 1, 2016. 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. From time to time 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, 2011, there was nothing outstanding under this facility.

• Approximately $700 million in short-term borrowing and letters of credit provided by various financial institutions. We use these facilities mainly to provide financial assurance for future decommissioning and reclamation of our operating sites, and as overdraft protection. At December 31, 2011, we had approximately $665 million outstanding in letters of credit.

We have $800 million in senior unsecured debentures:

• $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

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    43

We have issued a $73 million (US) promissory note to GLE to support future development of its business. In November 2011, GLE requested a drawing of $8 million (US) which included $7 million of accrued interest. The balance remaining on the note is $72 million (US).

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, 2011, we complied with all covenants, and we expect to continue to comply in 2012.

Off-balance sheet arrangements

We had two kinds of off-balance sheet arrangements at the end of 2011:

• purchase commitments

• financial assurances

Purchase commitments

December 31, 2011 ($ millions)	2012		2013 and 2014		2015 and 2016		2017 and beyond		Total
Purchase commitments1		308		581		128		440		1,457

¹  Denominated in US dollars, converted to Canadian dollars as of December 31, 2011 at the rate of $1.02.

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

At the end of 2011, we had committed to $1.5 billion (Cdn) for the following:

• About 35 million pounds of U₃O₈ equivalent from 2012 to 2027. Of these, about 17 million pounds are from our agreement with Techsnabexport Joint Stock Company (Tenex) to buy uranium from dismantled Russian weapons (the Russian HEU commercial agreement) through 2013.

• Over 30 million kgU as UF₆ in conversion services from 2012 to 2016 primarily under our agreements with Springfields Fuels Ltd. (SFL) and Tenex.

• Over 0.9 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-western supplier.

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

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

44    CAMECO CORPORATION

Financial assurances

December 31 ($ millions)	2011		2010		change
Standby letters of credit		670		550		22	%
BPLP guarantees		69		82		(16	)%
Total		739		632		17	%

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 $77 million at the end of the year. See note 31 to the financial statements.

Balance sheet

December 31 ($ millions except per share amounts)	2011		2010		Canadian GAAP 2009		change from 2010 to 2011
Inventory		494		533		453		(7	)%
Total assets		7,802		7,203		7,394		8	%
Long-term financial liabilities		1,743		1,530		1,437		14	%
Dividends per common share		0.40		0.28		0.24		43	%

Total product inventories decreased by 7% to $494 million this year due to lower levels of inventory for uranium, where the quantities sold exceeded quantities produced and purchased for the year. The average cost of uranium was higher as a result of the increasing costs of produced and purchased material. At December 31, 2011, our average cost for uranium was $25.11 per pound, up from $24.01 per pound at December 31, 2010. In 2010, total product inventories increased by 18% due to higher levels of uranium, where the quantities produced and purchased exceeded sales for the year. The average cost of uranium was lower as a result of fewer purchases at near-market prices.

At the end of 2011, our total assets amounted to $7.8 billion, an increase of $0.6 billion compared to 2010 due primarily to a higher rate of investment in property, plant and equipment. In 2010, the total asset balance decreased by $0.2 billion; on transition to IFRS, we expensed all borrowing costs that had been previously capitalized under Canadian GAAP.

The major components of long-term financial liabilities are long-term debt, finance lease obligations, the provision for reclamation and financial derivatives. In 2011, our balance increased by $0.2 billion. In 2010, our balance increased by $0.1 billion primarily due to adjustments as a result of the transition to IFRS. See note 3 to the financial statements.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    45

2011 financial results by segment

Uranium

Highlights	2011		2010		change
Production volume (million lbs)		22.4		22.8		(2	)%
Sales volume (million lbs)		32.9		29.6		11	%
Average spot price ($US/lb)		56.36		46.83		20	%
Average long-term price ($US/lb)		66.79		60.92		10	%
Average realized price
($US/lb)		49.17		43.63		13	%
($Cdn/lb)		49.18		45.81		7	%
Average unit cost of sales ($Cdn/lb) (including D&A)		29.94		27.87		7	%
Revenue ($ millions)		1,616		1,358		19	%
Gross profit ($ millions)		632		532		19	%
Gross profit (%)		39		39		—

Production volumes in 2011 were 2% lower than 2010 due to lower production from Smith Ranch-Highland and Inkai. See Operating properties on page 61 for more information.

Uranium revenues this year were up 19% compared to 2010, due to an 11% increase in sales volumes and an increase of 7% in the Canadian dollar average realized price. Sales volumes in 2011 were higher than 2010 due to some customers deferring 2010 deliveries under contracts until 2011. The 19% increase was higher than the guidance we provided in the third quarter (increase 10% to 15%) as sales volumes for 2011 were at the top of the range provided (31 million pounds to 33 million pounds) at that time.

Our realized prices this year in US dollars were 13% higher than 2010 mainly due to higher US dollar prices under market-related contracts. Our Canadian dollar selling price, however, was only 7% higher than 2010 as a result of a less favourable exchange rate when compared to 2010. Our exchange rate averaged $1.00 compared to $1.05 in 2010.

Total cost of sales (including D&A) increased by 19% this year ($983 million compared to $826 million in 2010). This was mainly the result of the following:

• the 11% increase in sales volumes

• average unit costs for produced uranium were 7% higher, although our average unit cost of sale for produced material was within the guidance we provided

• average unit costs for purchased uranium were 14% higher due to the increase in spot prices

• standby costs paid to AREVA relating to the McClean Lake mill

• higher royalty charges due to higher deliveries of Saskatchewan-produced material and higher realized prices. In 2011, total royalties rose to $124 million from $78 million in 2010.

The net effect was a $100 million increase in gross profit for the year.

46    CAMECO CORPORATION

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)	2011		2010		change
Produced
Cash cost		18.45		16.89		9	%
Non-cash cost		6.50		6.32		3	%
Total production cost		24.95		23.21		7	%
Quantity produced (million lbs)		22.4		22.8		(2	)%
Purchased
Cash cost		26.08		22.85		14	%
Quantity purchased (million lbs)		9.6		10.6		(9	)%
Totals
Produced and purchased costs		25.29		23.10		9	%
Quantities produced and purchased (million lbs)		32.0		33.4		(4	)%

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

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

To facilitate a better understanding of these measures, the table below presents a reconciliation of these measures to our unit cost of sales for the years ended 2011 and 2010 as reported in our financial statements.

Cash and total cost per pound reconciliation

($ millions)	2011			2010
Cost of product sold		824.3			691.3
Add / (subtract)
Royalties		(123.6	)		(78.2	)
Standby charges		(22.0	)		(12.0	)
Other selling costs		(9.4	)		(13.4	)
Change in inventories		(5.7	)		39.6
Cash operating costs (a)		663.6			627.3
Add / (subtract)
Depreciation and amortization		159.2			134.9
Change in inventories		(13.6	)		9.2
Total operating costs (b)		809.2			771.4
Uranium produced and purchased (millions lbs) (c)		32.0			33.4
Cash costs per pound (a ÷ c)		20.74			18.78
Total costs per pound (b ÷ c)		25.29			23.10

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    47

Outlook for 2012

We expect to produce 21.7 million pounds in 2012. In addition, we have commitments under long-term contracts to purchase about 8 million pounds.

Based on the contracts we have in place, we expect to sell between 31 million and 33 million pounds of U₃O₈ in 2012. We expect the average unit cost of sales to be 0% to 5% higher than in 2011. The increase is due primarily to higher costs for produced material. If we decide to make additional discretionary purchases in 2012 then we expect the average unit cost of sales to increase further.

Based on current spot prices, revenue should be about 0% to 5% lower than it was in 2011 as a result of an expected decrease in the realized price.

Our customers choose when in the year to receive deliveries of uranium and fuel services products, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly. In 2012, we expect that deliveries will be evenly distributed across the quarters. However, not all delivery notices have been received to date, which could alter the delivery pattern.

Price sensitivity analysis: uranium

The table below is not a forecast of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table.

It is designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2011 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, 2011, and none of the assumptions we list below change.

We intend to update this table 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 to change from quarter to quarter.

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)

($US/lb U3O8)
Spot prices	$	20	$	40	$	60	$	80	$	100	$	120	$	140
2012		38		42		50		57		66		74		81
2013		43		46		54		62		71		80		88
2014		45		48		56		65		74		83		91
2015		43		47		56		66		77		87		97
2016		45		50		58		68		78		88		97

The table illustrates the mix of long-term contracts in our December 31, 2011 portfolio, and is consistent with our contracting strategy. The table has been updated to December 31, 2011 to reflect:

• deliveries made and contracts entered into up to December 31, 2011

• changes to deliveries under some sales contracts to assist our customers who were directly impacted by the March nuclear incident in Japan

• changes to deliveries under some contracts where deliveries are tied to reactor requirements

Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. We signed many of our current contracts in 2003 to 2005, when market prices were low ($11 to $31 (US)). Those that are fixed at lower prices or have low ceiling prices will yield prices that are lower than current market prices. These older contracts are beginning to expire, and we are starting to deliver into more favourably priced contracts.

48    CAMECO CORPORATION

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

Sales

• sales volumes on average of 32 million pounds per year

Deliveries

• customers take the maximum quantity allowed under each contract (unless they have already provided a delivery notice indicating they will take less)

• we defer a portion of deliveries under existing contracts for 2012

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 14% 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 will be higher.

• we deliver all volumes that we do not have contracts for at the spot price for each scenario

Inflation

• is 3% per year

Tiered royalties

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

This table assumes that we sell 100,000 pounds U₃O₈ and that there is no capital allowance available to reduce royalties, and is based on 2011 government prescribed rates. The index value to calculate rates for 2012 is not available until April 2012.

Realized price ($Cdn)	Tier 1 royalty 6% x (sales price - $18.05)		Tier 2 royalty 4% x (sales price - $27.07)		Tier 3 royalty 5% x (sales price - $36.09)		Total royalties
25		41,700		—		—		41,700
35		101,700		31,720		—		133,420
45		161,700		71,720		44,550		277,970
55		221,700		111,720		94,550		427,970
65		281,700		151,720		144,550		577,970
75		341,700		191,720		194,550		727,970
85		401,700		231,720		244,550		877,970

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    49

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

Highlights	2011		2010		change
Production volume (million kgU)		14.7		15.4		(5	)%
Sales volume (million kgU)		18.3		17.0		8	%
Realized price ($Cdn/kgU)		16.71		16.86		(1	)%
Average unit cost of sales ($Cdn/kgU) (including D&A)		13.75		13.05		5	%
Revenue ($ millions)		305		287		6	%
Gross profit ($ millions)		54		65		(17	)%
Gross profit (%)		18		23		(22	)%

Total revenue increased by 6% due to an 8% increase in sales volumes.

The total cost of sales (including D&A) increased by 13% ($251 million compared to $222 million in 2010) due to the increase in sales volumes. The average unit cost of sales was 5% higher due to higher unit costs for UF₆ relating to lower production.

The net effect was a $11 million decrease in gross profit.

Outlook for 2012

Due to current unfavourable market conditions for UF₆ conversion, we are decreasing our production in 2012. We plan to produce between 13 million and 14 million kgU, and expect sales volumes in 2012 to be 10% to 15% lower than in 2011.

We are changing our fuel services product mix in 2012, producing and selling less UF₆ than in 2011. We will also realize fewer 2012 cost recoveries in UF₆ conversion. Therefore, in fuel services we expect:

• the average realized price for our fuel services products to increase by 0% to 5%

• revenue to decrease by 10% to 15%

• average unit cost of sales (including D&A) to increase by 10% to 15%

50    CAMECO CORPORATION

Electricity

BPLP

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

Highlights ($ millions except where indicated)	2011			2010			change
Output - terawatt hours (TWh)		24.9			25.9			(4	)%
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		87	%		91	%		(4	)%
Realized price ($/MWh)		54	1		58			(7	)%
Average Ontario electricity spot price ($/MWh)		30			36			(17	)%
Revenue		1,354			1,509			(10	)%
Operating costs (net of cost recoveries)		1,006			910			11	%
Cash costs		812			740			10	%
Non-cash costs		194			170			14	%
Income before interest and finance charges		348			599			(42	)%
Interest and finance charges		37			37			—
Cash from operations		490			669			(27	)%
Capital expenditures		243			136			79	%
Distributions		270			525			(49	)%
Capital calls		21			—			—
Operating costs ($/MWh)		40	1		35			14	%

¹ Based on actual generation of 24.9 TWh plus deemed generation of 0.4 TWh

Our earnings from BPLP

Highlights ($ millions except where indicated)	2011			2010			change
BPLP’s earnings before taxes (100%)		311			562			(45	)%
Cameco’s share of pretax earnings before adjustments (31.6%)		98			178			(45	)%
Proprietary adjustments		(6	)		(6	)		—
Earnings before taxes from BPLP		92			172			(47	)%

BPLP’s results in 2011 are largely the result of lower revenues, which were 10% lower than 2010 due to a 7% 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 $50.18/MWh) that is adjusted annually for inflation. The floor price mechanism and any associated payments to BPLP for the output from each individual B reactor will expire on a date specified in the agreement. The expiry dates are December 31, 2015 for unit B6, December 31, 2016 for unit B5, December 31, 2017 for unit B7 and December 31, 2019 for unit B8. Revenue is recognized monthly, based on the positive difference between the floor price and the spot price. BPLP does not have to repay the revenue from the agreement with the OPA to the extent that the floor price for the particular year exceeds the average spot price for that year.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    51

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. Deemed generation was 0.4 TWh in 2011.

During 2011, BPLP recognized revenue of $498 million under the agreement with the OPA, compared to $339 million in 2010.

BPLP also has financial contracts in place that reflect market conditions at the time they were signed. Contracts signed in 2006 to 2008, when the spot price was higher than the floor price, reflected the strong forward market at the time. BPLP receives or pays the difference between the contract price and the spot price. BPLP sold the equivalent of about 54% of its output under financial contracts in 2011, compared to 42% in 2010. Pricing under these contracts was lower than in 2010. From time to time, BPLP enters the market to lock in gains under these contracts.

BPLP’s operating costs were $1.0 billion this year compared to $910 million in 2010 due to higher maintenance costs incurred during outage periods and increased staff costs.

The net effect was a decrease in our share of earnings before taxes of 47%.

BPLP distributed $270 million to the partners in 2011. Our share was $85 million. BPLP capital calls to the partners in 2011 were $21 million. Our share was $7 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

BPLP’s capacity factor was 87% in 2011, down from 91% in 2010 due to a higher volume of outage days during the year’s planned outages compared to last year’s planned outages.

Outlook for 2012

Bruce Power estimates the average capacity factor for the four Bruce B reactors to be 95% in 2012, and actual output to be about 9% higher than it was in 2011 due to fewer planned outage days in 2012. The 2012 realized price for electricity is projected to be about the same as 2011. As a result we expect that revenue will increase by 5% to 10%.

We expect the average unit cost (net of cost recoveries) to be 5% to 10% lower in 2012 and total operating costs to decrease by about 0% to 5%, mainly due to fewer planned outages resulting in lower costs.

52    CAMECO CORPORATION

Fourth quarter results

Fourth quarter consolidated results

Highlights	Three months ended December 31
($ millions except per share amounts)	2011		2010		change
Revenue		977		673		45	%
Gross profit		353		252		40	%
Net earnings		265		206		29	%
$ per common share (basic)		0.67		0.52		29	%
$ per common share (diluted)		0.67		0.52		29	%
Adjusted net earnings (non-IFRS, see pages 33 & 34)		249		190		31	%
$ per common share (adjusted and diluted)		0.63		0.48		31	%
Cash provided by operations (after working capital changes)		255		109		134	%

In the fourth quarter of 2011, our net earnings were $265 million ($0.67 per share diluted), an increase of $59 million compared to $206 million ($0.52 per share diluted) in 2010. Uranium revenues were up significantly due to an increase in sales volumes, an increase in the average realized selling price and partially offset by lower results in the electricity business due to lower sales volumes and a lower realized price.

The 31% increase in adjusted net earnings in the quarter followed the same trend as our net earnings, due to our positive results in the uranium business partially offset by our results in the electricity business.

We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our financial performance from period to period. See pages 33 & 34 for more information. The table below reconciles adjusted net earnings with our net earnings.

	Three months ended December 31
($ millions)	2011			2010
Net earnings		265			206
Adjustments
Adjustments on derivatives1 (pre-tax)		(22	)		(22	)
Income taxes on adjustments to derivatives		6			6
Adjusted net earnings		249			190

¹ In 2008, we opted to discontinue hedge accounting for our portfolio of foreign currency forward sales contracts. Since then, we have adjusted our gains and losses on derivatives as reported under IFRS to reflect what our earnings would have been had hedge accounting been applied.

We recorded an income tax expense of $25 million this quarter, based on adjusted net earnings, compared to a $1 million expense in 2010.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    53

Direct administration costs were $46 million in the quarter, $6 million lower than the same period last year. Stock-based compensation expenses were $2 million higher than the fourth quarter of 2010 at $3 million. See note 27 to the financial statements.

	Three months ended December 31
($ millions)	2011		2010		change
Direct administration		46		52		(12	)%
Stock-based compensation		5		3		67	%
Total administration		51		55		(7	)%

Quarterly trends

Highlights	2011								2010
($ millions except per share amounts)	Q4		Q3		Q2		Q1		Q4		Q3			Q2		Q1
Revenue		977		527		426		454		673		419			546		486
Net earnings		265		39		55		91		206		97			70		143
$ per common share (basic)		0.67		0.10		0.14		0.23		0.52		0.25			0.18		0.36
$ per common share (diluted)		0.67		0.10		0.14		0.23		0.52		0.25			0.18		0.36
Adjusted net earnings (non-IFRS, see page 33 )		249		104		72		84		190		79			116		112
$ per common share (adjusted and diluted)		0.63		0.26		0.18		0.22		0.48		0.21			0.29		0.28
Cash provided by operations (after working capital changes)		255		190		20		267		109		(5	)		271		146

Key things to note:

• Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 75% of consolidated revenues in the fourth quarter of 2011.

• The timing of customer requirements, which tend 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 pages 33 & 34 for more information).

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

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

54    CAMECO CORPORATION

Fourth quarter results by segment

Uranium

Highlights	Three months ended December 31				change
	2011		2010
Production volume (million lbs)		6.6		6.4		3	%
Sales volume (million lbs)		13.8		9.1		52	%
Average spot price ($US/lb)		51.79		58.29		(11	)%
Average long-term price ($US/lb)		62.50		64.33		(3	)%
Average realized price
($US/lb)		52.09		48.51		7	%
($Cdn/lb)		53.08		50.10		6	%
Average unit cost of sales ($Cdn/lb) (including D&A)		30.29		29.38		3	%
Revenue ($ millions)		731		457		60	%
Gross profit ($ millions)		314		189		66	%
Gross profit (%)		43		41		5	%

Production volumes were 3% higher due to slightly higher output at Rabbit Lake and Inkai, partially offset by slightly lower output at McArthur River/Key Lake and Smith Ranch-Highland. See Operating properties on page 61 for more information.

Uranium revenues were up 60% due to a 6% increase in the Canadian dollar average realized price, and a 52% increase in sales volumes.

Our realized prices this quarter were higher than the fourth quarter of 2010 mainly due to higher US dollar prices under market related contracts, partially offset by a less favourable exchange rate. In the fourth quarter of 2011, our realized foreign exchange rate was $1.02 compared to $1.03 in the prior year.

Total cost of sales (including D&A) increased by 56% ($417 million compared to $268 million in 2010). This was mainly the result of the following:

• the 52% increase in sales volumes

• higher royalty charges due to higher deliveries of Saskatchewan-produced material and higher realized prices

• average unit costs for produced uranium were 2% higher

• partially offset by 33% lower average unit costs for purchased uranium due to fewer purchases at spot prices

The net effect was a $125 million increase in gross profit for the quarter.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    55

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)	Three months ended December 31				change
	2011		2010
Produced
Cash cost		17.44		15.94		9	%
Non-cash cost		5.52		6.52		(15	)%
Total production cost		22.96		22.46		2	%
Quantity produced (million lbs)		6.6		6.4		3	%
Purchased
Cash cost		18.86		28.14		(33	)%
Quantity purchased (million lbs)		2.3		4.3		(47	)%
Totals
Produced and purchased costs		21.90		24.74		(11	)%
Quantities produced and purchased (million lbs)		8.9		10.7		(17	)%

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

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.

56    CAMECO CORPORATION

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 fourth quarters of 2011 and 2010.

Cash and total cost per pound reconciliation

($ millions)	Three months ended December 31
	2011			2010
Cost of product sold		336.8			230.9
Add / (subtract)
Royalties		(61.3	)		(18.2	)
Standby charges		(6.0	)		(6.4	)
Other selling costs		(2.8	)		(7.9	)
Change in inventories		(108.2	)		24.6
Cash operating costs (a)		158.5			223.0
Add / (subtract)
Depreciation and amortization		80.1			37.3
Change in inventories		(43.7	)		4.4
Total operating costs (b)		194.9			264.7
Uranium produced & purchased (millions lbs) (c)		8.9			10.7
Cash costs per pound (a ÷ c)		17.81			20.84
Total costs per pound (b ÷ c)		21.90			24.74

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    57

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

Highlights	Three months ended December 31				change
	2011		2010
Production volume (million kgU)		3.1		3.9		(21	)%
Sales volume (million kgU)		7.2		6.3		14	%
Realized price ($Cdn/kgU)		14.66		14.59		—
Average unit cost of sales ($Cdn/kgU) (including D&A)		11.18		12.49		(10	)%
Revenue ($ millions)		106		91		16	%
Gross profit ($ millions)		25		13		92	%
Gross profit (%)		24		14		71	%

Production volumes were 21% lower than in 2010 due to the decrease in production of UF₆. We reduced our production forecast in the third quarter as a result of unfavourable market conditions.

Total revenue increased by 16% due to a 14% increase in sales volumes and a slight increase in realized price.

The total cost of sales (including D&A) increased by 4% ($81 million compared to $78 million in the fourth quarter of 2010) due to the increase in sales volumes. When compared to 2010, the average unit cost of sales was 10% lower primarily due to higher cost recoveries in 2011.

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

58    CAMECO CORPORATION

Electricity

BPLP

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

Highlights ($ millions except where indicated)	Three months ended December 31						change
	2011			2010
Output - terawatt hours (TWh)		6.2			6.6			(6	)%
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		86	%		91	%		(6	)%
Realized price ($/MWh)		53	1		60			(12	)%
Average Ontario electricity spot price ($/MWh)		27			32			(16	)%
Revenue		338			393			(14	)%
Operating costs (net of cost recoveries)		271			225			20	%
Cash costs		220			183			20	%
Non-cash costs		51			42			21	%
Income before interest and finance charges		67			168			(60	)%
Interest and finance charges		7			7			—
Cash from operations		114			147			(22	)%
Capital expenditures		84			38			121	%
Distributions		65			120			(46	)%
Capital calls		10			—			—
Operating costs ($/MWh)		42	1		34			24	%

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

Our earnings from BPLP

Highlights ($ millions except where indicated)	Three months ended December 31						change
	2011			2010
BPLP’s earnings before taxes (100%)		60			161			(63	)%
Cameco’s share of pretax earnings before adjustments (31.6%)		19			51			(63	)%
Proprietary adjustments		(2	)		(2	)		—
Earnings before taxes from BPLP		17			49			(65	)%

Total electricity revenue decreased 14% due to lower output and a lower realized price. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA, and financial contract revenue. BPLP recognized revenue of $147 million this quarter under its agreement with the OPA, compared to $114 million in the fourth quarter of 2010. The equivalent of about 66% of BPLP’s output was sold under financial contracts this quarter, compared to 45% in the fourth quarter of 2010. From time to time BPLP enters the market to lock in gains under these contracts.

The capacity factor was 86% this quarter, down from 91% in the fourth quarter of 2010 due to a higher volume of outage days during the year’s planned outages compared to last year’s planned outages.

Operating costs were $271 million compared to $225 million in 2010 due to higher maintenance costs incurred during outage periods and increased staff costs.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    59

The result was a 65% decrease in our share of earnings before taxes.

BPLP distributed $65 million to the partners in the fourth quarter. Our share was $21 million. BPLP capital calls to the partners in the fourth quarter were $10 million. Our share was $3 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

60    CAMECO CORPORATION

Our operations and development projects

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

Uranium
Operating properties
McArthur River and Key Lake	67
Rabbit Lake	73
Smith Ranch-Highland	75
Crow Butte	77
Inkai	79
Development project
Cigar Lake	83
Projects under evaluation
Inkai blocks 1 and 2 production increase (see Inkai, above)	79
Inkai block 3 (see Inkai, above)	79
McArthur River extension
(see McArthur River, above)	67
Kintyre	89
Millennium	90
Exploration	91
Fuel services
Refining
Blind River refinery	92
Conversion and fuel manufacturing
Port Hope conversion services	93
Fuel Manufacturing	93
Springfields Fuels	93
Electricity
Bruce Power Limited Partnership	95

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    61

Managing the risks

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

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

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

Regulatory risks

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

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

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

• comply with the extensive and complex laws and regulations that govern our activities, including our growth plans. Environmental legislation imposes very 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 an environmental assessment before we can begin developing a new mine or make any significant change to our operations

• we increasingly need regulatory approval to make changes to our operational processes, which can take a significant amount of time because it may require an environmental assessment or an extensive review of supporting 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.

62    CAMECO CORPORATION

Environmental risks

We have the safety, health and environmental risks associated with any mining and chemical processing company. All three of our business 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 regulator. We have developed conceptual decommissioning plans for our operating sites and use them to estimate our decommissioning costs. As the site approaches or goes into decommissioning, regulators review our detailed decommissioning plan and carry out the required regulatory approval process. This can result in further regulatory process, as well as additional requirements, costs and financial assurances.

At the end of 2011, our estimate of total decommissioning and reclamation costs was $577 million. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $509 million at the end of 2011 (the present value of the $577 million). Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, our expected costs for decommissioning and reclamation for the next five years are not material.

We provide financial assurances for decommissioning and reclamation such as letters of credit to regulatory authorities, as required. We had a total of $664 million in letters of credit supporting our reclamation liabilities at the end of 2011. Since 2001, all of our North American operations have had 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 SHEQ management system is centralized and managed at the corporate level, and we implement it corporately and at our operations. 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 2011, we invested:

• $99 million in environmental protection, monitoring and assessment programs, or 30% more than 2010

• $30 million in health and safety programs, which is 12% less than we spent in 2010

In 2012, spending for health and safety programs is expected to be similar to 2011, while spending for environmental programs is expected to increase slightly.

Lessons learned from Japan

In response to the events in Japan this year, the Canadian Nuclear Safety Commission (CNSC) asked us to review the risk management and emergency preparedness processes at all of our Canadian sites, under subsection 12(2) of the General Nuclear Safety and Control Regulations.

Our uranium and fuel services divisions retained third-party experts to carry out the reviews, and these were completed and submitted to the CNSC this year.

The evaluations focused on the potential effects of extreme natural events on human health and the environment, and the risk management and emergency preparedness processes we have in place to prevent, mitigate and respond. The review concluded that the multi-layer system we have in place at all of our operations—our five levels of defence—provides multiple and effective barriers against the potential effects of a natural disaster.

We are considering other recommendations we received as we continue to improve our designs, practices, policies and plans to ensure worker and public safety. We do not expect any of the recommendations to require material expenditures.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    63

Operational risks

Other operational risks and hazards include:

• environmental damage

• industrial and transportation accidents

• labour shortages, disputes or strikes

• cost increases for 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.

64    CAMECO CORPORATION

Uranium – production overview

Our production was 2% lower in 2011 than it was in 2010, but 3% higher than the guidance we provided in our third quarter MD&A. We had a number of successes at our mining operations in 2011.

At McArthur River/Key Lake:

• realized benefits of production flexibility provisions in our McArthur River/Key Lake licences, matching our 2010 production record and exceeding our production target by 5%

• realized benefits of improved efficiency and reliability of equipment at Key Lake

At Inkai:

• received government approval allowing us to increase production to 3.9 million pounds (100% basis)

• signed an MOA to increase production to 5.2 million pounds (100% basis)

Uranium production

Cameco’s share (million lbs)	Three months  ended December 31				Year ended December 31				2011 plan
	2011		2010		2011		2010
McArthur River/Key Lake		3.9		4.0		13.9		13.9		13.3
Rabbit Lake		1.6		1.3		3.8		3.8		3.6
Smith Ranch-Highland		0.2		0.4		1.4		1.8		1.6
Crow Butte		0.2		0.2		0.8		0.7		0.7
Inkai		0.7		0.5		2.5		2.6		2.5
Total		6.6		6.4		22.4		22.8		21.7	1

¹  We updated our 2011 plan in our Q3 MD&A to 21.7 million pounds from 21.9 million pounds at the beginning of 2011.

Outlook

We have geographically diverse sources of production. Our strategy is to increase our annual production to 40 million pounds by 2018, which we expect will come from our operating properties, development projects and projects under evaluation.

Cameco’s share of production — annual forecast to 2016

Current forecast (million lbs)	2012		2013		2014		2015		2016
McArthur River/Key Lake		13.1		13.1		13.1		13.1		13.1
Rabbit Lake		3.7		3.7		3.7		3.7		3.4
US ISR		2.4		3.0		3.1		3.7		3.8
Inkai1		2.5		2.9		2.9		2.9		2.9
Cigar Lake		—		0.3		1.9		5.5		7.9
Total share of production		21.7		23.0		24.7		28.9		31.1
Cameco’s share of Inkai’s production on which profits are generated2
Inkai1		2.6		3.0		3.0		3.0		3.0
Total2		21.8		23.1		24.8		29.0		31.2

¹ We have signed an MOA with Kazatomprom to increase annual production to 5.2 million pounds (100% basis). Once implemented, we will receive the right to purchase 2.9 million pounds of Inkai’s annual production and receive profits on 3.0 million pounds. See page 79 for more information.

² We have adjusted the production table to reflect the share of Inkai’s production we will use to calculate our profits under the MOA. See page 79 for more information.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    65

In 2013, production at McArthur River may be lower as we transition to mining upper zone 4.

Our 2012 and future annual production targets for Inkai assume, and we expect:

• Inkai will obtain the necessary government permits and approvals to produce at an annual rate of 5.2 million pounds (100% basis), including an amendment to the resource use contract

• we reach a binding agreement with Kazatomprom to finalize the terms of the MOA

• Inkai will ramp up production to an annual rate of 5.2 million pounds (100% basis)

There is no certainty Inkai will receive these permits or approvals or we will reach a binding agreement with Kazatomprom or that Inkai will be able to ramp up production. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2012 and future annual production targets and we may have to recatagorize some of Inkai’s mineral reserves as resources.

This forecast is forward-looking information. It is based on the assumptions and subject to the material risks discussed on page 3, and specifically on the assumptions and risks noted above and listed here. Actual production may be significantly different from this forecast.

Assumptions

• we achieve our forecast production for each operation, which requires, among other things, that our mining plans succeed, processing plants and equipment are available and function as designed, we have sufficient tailings capacity and our mineral reserve estimates are reliable

• we obtain or maintain the necessary permits and approvals from government authorities

• our production is not disrupted or reduced as a result of natural phenomena, labour disputes, political risks, blockades or other acts of social or political activism, shortage or lack of supplies critical to production, equipment failures or other development and operation risks

Material risks that could cause actual results to differ materially

• we do not achieve forecast production levels for each operation because of a change in our mining plans, processing plants or equipment are not available or do not function as designed, lack of tailings capacity or for other reasons

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

• natural phenomena, labour disputes, political risks, blockades or other acts of social or political activism, shortage or lack of supplies critical to production, equipment failures or other development and operation risks disrupt or reduce our production

66    CAMECO CORPORATION

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)	226.2 million pounds (proven and probable) average grade U3O8: 16.89%
Estimated resources (our share)	51.0 million pounds (measured and indicated) average grade U3O8: 17.63% 60.3 million pounds (inferred) average grade U3O8 : 9.67%
Mining methods	currently: raiseboring pending regulatory approval: blasthole stoping under development: boxhole boring
Licensed capacity	mine and mill: 18.7 million pounds per year (can be exceeded – see Production Flexibility)
Total production  2000 to 2011	211 million pounds (McArthur River/Key Lake) (100% basis)
1983 to 2002	209.8 million pounds (Key Lake) (100% basis)
2011 production	13.9 million pounds (our share)
2012 forecast production	13.1 million pounds (our share)
Estimated decommissioning cost	$36.1 million – McArthur River
	$120.7 million – Key Lake

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    67

Background

Production flexibility

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

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

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

If production is lower than 18.7 million pounds in any year, we can produce more in future years until we recover the shortfall. We still have the opportunity to recover past production shortfalls of about 2.5 million pounds (100% basis) at Key Lake mill and about 3.5 million pounds (100% basis) at McArthur River.

Mining methods and techniques

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 water from entering the mine, and helps stabilize weak rock formations.

In 2009, we developed an innovative, cathedral-shaped freezewall around zone 2, panel 5, allowing us to develop tunnels above and below the orebody. We expect this innovation will allow us to continue using raisebore mining as the main mining method at McArthur River and improve production efficiencies as we transition to other areas of the mine (see Planning for the future – New mining zones).

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 ore

• 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

• filling each raisebore hole with concrete once mining is complete

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

• starting the process again with the next raisebore chamber

We have used the raisebore mining method to successfully extract about 210 million pounds (100% basis) since we began mining in 1999.

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McArthur River currently has four zones with delineated mineral reserves (zones 1 to 4). Parts of zones 1, 2, 3 and 4 also have mineral resources. In addition, zones A and B to the north contain mineral resources.

We have mined from zone 2 since the mine started production. Zone 2 is divided into four panels (panels 1, 2, 3 and 5). Until late 2009, all mine production was from panels 1, 2 and 3, and there are still limited reserves that we will extract from these panels in the next few years. Panel 5 represents the upper portion of zone 2, overlying a portion of the other panels.

We successfully transitioned to panel 5 in 2009, the first time development has been accomplished through the unconformity into the Athabasca sandstone.

In late 2010, we brought the lower mining area of zone 4 into production.

Boxhole boring

Given our success with the cathedral-shaped freezewall around zone 2, panel 5, the use of boxhole boring in our mine plan has been significantly narrowed in scope. We expect to be able to continue using raisebore mining as our main mining method for McArthur River.

Boxhole boring is similar to the raisebore method, but the drilling machine is located below the orebody, so development is not required above the orebody. This method is currently being used at only a few mines around the world, but has not been used for uranium mining.

Boxhole boring poses some technical challenges. We will continue to test this method in 2012; however, we expect it will only be used as a secondary method, in areas where we determine raiseboring is not feasible. Boxhole boring may not be as productive as the raisebore method, but we will be able to determine this more accurately once we have fully developed and tested the method at McArthur River.

Blasthole stoping

Blasthole stoping involves establishing drill access above the ore and extraction access below the ore. The area between the upper and lower access levels (the stope) is then drilled off and blasted. The broken rock and ore are collected on the lower level and removed by line-of-sight remote-controlled scoop trams, then transported to a

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    69

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 for mining uranium.

Blasthole stoping is being evaluated for the recovery of small isolated, lower grade ore zones away from the freezewalls and where raisebore or boxhole boring is uneconomic or impractical. We mined our first blasthole stope in the fourth quarter of 2011, in lower zone 4, with good productivity.

2011 update

Production

Our share of production in 2011 was 5% higher than our target of 13.3 million pounds, and the same as 2010.

At McArthur River and Key Lake we matched our production record set in 2010, realizing benefits under the production flexibility amendments to the McArthur River and Key Lake operating licences (see Production flexibility). Our revitalization program has improved the efficiency and reliability of equipment at the Key Lake mill, which had record monthly production in the latter part of the year.

New mining areas

Upper zone 4 – we began drilling for the freezewall required to bring the upper mining area of zone 4 into production.

Mill revitalization

The Key Lake mill began operating in 1983. We are revitalizing the mill to ensure sustained reliable production and increase our uranium production capability.

The Key Lake revitalization plan includes upgrading circuits with new technology to simplify operations and improve environmental performance. After the mill is revitalized, annual production will depend mainly on mine production. As part of this plan, we replaced the acid, steam and oxygen plants.

At the end of 2011, construction of all three plants was complete. The steam plant was commissioned at year end and the oxygen plant was commissioned in early 2012. We have started commissioning the acid plant.

Tailings capacity

The regulator approved the guidelines for our Key Lake extension project, which proposes to:

• allow continued processing of ore from the McArthur River mine and other potential mine developments

• increase long-term capacity of the Deilmann tailings management facility by allowing us to deposit tailings to a higher elevation

• increase annual mill production capacity to 25 million pounds (100% basis)

We are currently drafting the environmental impact study for submission to the regulator as part of the environmental assessment process. This year we:

• completed the detailed design for the stabilization of the Deilmann tailings management facility pitwalls

• relocated the infrastructure necessary to allow us to flatten the slope of the pitwalls

• continued our work on the environmental assessment for the Key Lake extension project

McArthur River extension

In addition to the exploration work discussed below, we advanced feasibility work on the McArthur River extension project this year. This is a multi-year project to safely expand the underground mine and develop new mining areas.

Our plan is to:

• increase average annual production at the mine from 18.7 million pounds (100% basis) to 22 million pounds (100% basis)

• construct the infrastructure necessary to support production at this level

• further delineate mineral resources to the north and south of the current mining operations

An environmental assessment is required for the potential increase in production. Other work on this project will be approved through regular licensing activities.

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Exploration

As part of the McArthur River extension, we advanced the exploration drifts to zones A and B, north of current mining operations, and were successful in upgrading the majority of the zone B inferred mineral resources to the indicated category based on surface drilling. This area continues to show promise.

Planning for the future

Production

We expect our share of production to be 13.1 million pounds in 2012 and we will continue to look for opportunities to take advantage of the production flexibility provision in our licences.

New mining zones

Zone 4 – In 2012, we will continue the drilling to install the freezewall required to bring the upper mining area of zone 4 into production. We expect to start freezing upper zone 4 in 2013 and begin production from this area 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.

Mill revitalization

In 2012, we expect to:

• complete the commissioning of the new acid plant

• begin work for the construction of a new electrical substation and calciner

Tailings capacity

In 2012, we expect to:

• begin to flatten the slope of the Deilmann tailings management facility pitwalls

• advance the environmental assessment for the Key Lake extension project. We expect to submit the draft environmental impact statement to the regulators by the end of the second quarter. Comments on the draft are expected before year end.

Exploration

In 2012, we plan to continue advancing the underground exploration drift to the south of the current mining areas. We also plan to test, from surface, along the entire length of the mineralized zone to identify additional mineral resources.

Managing our risks

Production at McArthur River/Key Lake poses many challenges: control of groundwater, weak rock formations, radiation protection, water inflow, mining method uncertainty and changes to productivity, mine transitioning, regulatory approvals, tailings capacity, reliability of facilities at Key Lake, surface and underground fires. Operational experience gained since the start of production has resulted in a significant reduction in risk.

Water inflow risk

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

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

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.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    71

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

Key Lake tailings capacity risk

Tailings from processing McArthur River ore are deposited in the Deilmann tailings management facility. At current production rates, the licensed capacity of the Deilmann tailings management facility is about six years, assuming we experience only minor losses in storage capacity due to sloughing from the pitwalls. Significant sloughing could constrain McArthur River production.

Sloughing of material from the pitwalls in the past has resulted in the 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. We doubled our dewatering treatment capacity, allowing us to stabilize the water level in the pit. The water level has been gradually reduced over the past three and a half years.

In 2009, regulators approved our plan for the long-term stabilization of the Deilmann tailings management facility pitwalls. We are implementing the plan, and expect it will take approximately three years to complete the work.

We have also looked at options for long-term storage of tailings at Key Lake. We are proceeding with the environmental assessment to support an application for regulatory approval to deposit tailings in the Deilmann tailings management facility to a much higher level. This would provide us with enough tailings capacity to potentially mill a volume equal to all the known mineral reserves and resources from McArthur River and additional capacity to toll mill ore from other regional deposits.

We also manage the risks listed on pages 62 to 64.

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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 reserves	24.0 million pounds (proven and probable) average grade U3O8: 0.73%
Estimated resources	4.3 million pounds (indicated) average grade U3O8: 0.53% 10.4 million pounds (inferred) average grade U3O8 : 1.42%
Mining method	vertical blasthole stoping
Licensed capacity	mill: maximum 16.9 million pounds per year; currently 11 million
Total production 1975 to 2011	186.3 million pounds
2011 production	3.8 million pounds
2012 forecast production	3.7 million pounds
Estimated decommissioning cost	$105.2 million

2011 update

Production

Production this year was about 6% higher than our plan and the same as it was in 2010.

Mill upgrades

During our scheduled mill maintenance shutdown in the third quarter, we completed the second phase of upgrades at the acid plant, successfully replacing the acid plant final towers.

We signed an agreement with our joint venture partners which changes the milling arrangements for the ore from Cigar Lake. See Uranium - development project Cigar Lake on page 83 for more information.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    73

We received regulatory approval to begin exploration-related development and drilling on the Powell Zone, and completed a portion of the development work. We plan to complete the development work in 2012 and carry out drilling to further evaluate this zone.

Planning for the future

Production

We expect to produce 3.7 million pounds in 2012.

Tailings Capacity

We expect to have sufficient tailings capacity to support milling of Eagle Point ore until approximately mid-2016.

We are planning to expand the existing tailings management facility by mid-2016, to increase the tailings capacity so that it can support the extension of Rabbit Lake’s mine life and provide additional tailings capacity to process ore from other potential sources. The regulators will need to approve an environmental assessment before we can proceed.

Exploration

We have extended our underground drilling reserve replacement program into 2012. We plan to test and evaluate areas east and northeast of the mine where we have had good results, and to the north and south. This drilling will largely be from surface.

Reclamation

As part of our multi-year site-wide reclamation plan, we expect to spend over $2 million in 2012 to reclaim facilities that are no longer in use.

Managing our risks

We manage the risks listed on pages 62 to 64.

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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 processes all the uranium. 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	6.6 million pounds (proven and probable) average grade U3O8: 0.09%
Estimated resources	23.7 million pounds (measured and indicated) average grade U3O8 : 0.06% 6.6 million pounds (inferred) average grade U3O8: 0.05%
Mining method	in situ recovery (ISR)
Licensed capacity	wellfields: 2 million pounds per year processing plants: 5 million pounds per year including Highland mill
Total production 2002 to 2011	15 million pounds
2011 production	1.4 million pounds
2012 forecast production	1.7 million pounds
Estimated decommissioning cost	$168 million (US)

2011 update

Production

Production this year was 22% lower than 2010 and 13% lower than our plan. The review process to obtain regulatory approvals has lengthened at Smith Ranch-Highland, which has increased the timeline to bring new wellfields into production.

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.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    75

Processing

In the fourth quarter, we signed a toll processing agreement with Uranerz Energy Corporation to process up to 800,000 pounds per year at the Smith Ranch-Highland processing plants. The agreement allows us to use excess plant capacity.

Planning for the future

Production

We expect to produce 1.7 million pounds in 2012.

We continue to seek regulatory approvals to proceed with expansions at our various satellite operations; however, we are experiencing some delays in receiving the necessary regulatory approvals. We recognize the regulators have a large volume of permits to process. We are working with them to improve communications and ensure we better understand and meet their needs. We are advancing work on satellite properties where prior approvals are in place.

Exploration

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

Managing our risks

The operating environment is becoming more complex as public interest and regulatory oversight increase. This may affect our plans to increase production. We also manage the risks listed on pages 62 to 64.

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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	3.7 million pounds (proven) average grade U3O8: 0.13%
Estimated resources	11.9 million pounds (indicated) average grade U3O8 : 0.21% 6.0 million pounds (inferred) average grade U3O8: 0.12%
Mining method	in situ recovery (ISR)
Licensed capacity (processing plant and wellfields)	1 million pounds per year
Total production 2002 to 2011	7.6 million pounds
2011 production	0.8 million pounds
2012 forecast production	0.7 million pounds
Estimated decommissioning cost	$35.6 million (US)

2011 update

Production

Production this year was 14% higher than 2010 and our forecast for the year.

Licensing

The regulators continued to review our applications to expand and relicense Crow Butte. They are planning public hearings in 2012 to consider our application. We are allowed to continue with all previously approved activities during the licence renewal process.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    77

Planning for the future

Production

In 2012, we expect to produce 0.7 million pounds.

We are seeking regulatory approvals to proceed with expansions at our various satellite operations; however, we are experiencing some delays in receiving the necessary regulatory approvals. We recognize the regulators have a large volume of permits to process. We are working with them to improve communications and ensure we better understand and meet their needs.

Managing our risks

The operating environment is becoming more complex as public interest and regulatory oversight increase. This may affect our plans to increase production. We also manage the risks listed on pages 62 to 64.

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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
ISO certification	BSI OHSAS 18001 ISO 14001 certified
Estimated reserves (our share)	59.7 million pounds (proven and probable) average grade U3O8 : 0.07%
Estimated resources (our share)	28.8 million pounds (indicated) average grade U3O8: 0.08% 153.0 million pounds (inferred) average grade U3O8 : 0.05%
Mining method	in situ recovery (ISR)
Licensed capacity (wellfields)	approved: 3.9 million pounds per year (our share 2.3 million pounds per year) application: 5.2 million pounds per year (our share 2.9/3.0 million pounds per year – see Licensing)
Total production 2008 to 2011	6.5 million pounds (our share)
2011 production	2.5 million pounds (our share)
2012 forecast production	4.3 million pounds (100% basis) (our share of production 2.5 million pounds – see Licensing)
Estimated decommissioning cost	$11 million (US)

2011 update

Production

Production this year was in line with the currently approved production level, but about 4% lower than production in 2010. Lower production was a result of in-process uranium inventory changes. Prior to final commissioning of the processing facilities in 2010, the in-process uranium inventory had built up. A significant reduction of this inventory added to production in 2010.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    79

In addition, production in 2010, the first full year of operation, benefited from the higher grades associated with new wellfields. Average grades at in situ recovery operations typically stabilize at levels lower than initial years because uranium is recovered from a mix of wellfields of varying maturities and, as wellfields mature, the grades decrease. 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 planning to expand the existing satellite plant capacity in order to support this production rate from lower grade solution. Regulatory approval is required to carry out production at the annual rate of 5.2 million pounds per year (100% basis).

Operations

Inkai experienced brief interruptions to its sulphuric acid supply during the year, which had a small impact on production. The supply of sulphuric acid is tight in Kazakhstan.

Project funding

We have a loan agreement with Inkai. As of December 31, 2011, there was:

• $192 million (US) of principal outstanding on the loan (in 2011 Inkai repaid $122 million (US) of principal)

• a nominal amount of accrued interest and financing fees on the loan. In 2011, Inkai paid $6 million (US) in accrued interest and financing fees.

Inkai uses 100% of the cash available for distribution every year to pay accrued interest and financing fees. After these are paid, Inkai uses 80% of the remaining cash available for distribution to repay principal outstanding on the loan until it is repaid in full. The final 20% is distributed as dividends to the owners.

We have also agreed to advance funds for Inkai’s work on block 3 until the feasibility study is complete.

Licensing

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

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

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

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

To implement the increase, we need a binding agreement finalizing the terms of the MOA, government approval and an amendment to the resource use contract.

Block 3 exploration

Inkai continued delineation drilling, began infrastructure development and completed engineering for a test leach facility for the block 3 assessment program. Regulatory approval of the detailed delineation and test leach work programs is required.

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

Uranium conversion project

Under the guidance of the memorandum of understanding (MOU) signed in 2007 (see Doubling production), we continued to work with our partner Kazatomprom to evaluate joint UF₆ conversion opportunities. This work includes examining the feasibility of a number of options and locations based on strategic and economic considerations.

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Planning for the future

Production

We expect our share of production to be 2.5 million pounds in 2012.

Block 3 exploration

In 2012 we expect to continue delineation drilling and development of a test leach facility.

Doubling production

As part of our strategy, we are working with our partner, Kazatomprom, to implement our 2007 non-binding MOU. The memorandum:

• targets future annual production capacity at 10.4 million pounds (100% basis). Our share of the additional capacity is expected to be 50%.

• contemplates studying the feasibility of constructing a uranium conversion facility as well as other potential collaborations in uranium conversion

To implement the increase, we need a binding agreement to finalize the terms of the MOU, and various approvals from our partner and the government. We expect our ability to double annual uranium production at Inkai will be closely tied to the success of the uranium conversion project.

Managing our risks

Regulatory approvals

Our 2012 and future annual production targets for Inkai assume, and we expect:

• Inkai will obtain the necessary government permits and approvals to produce at an annual rate of 5.2 million pounds (100% basis), including an amendment to the resource use contract

• we reach a binding agreement with Kazatomprom to finalize the terms of the MOA

• Inkai will ramp up production to an annual rate of 5.2 million pounds (100% basis)

There is no certainty Inkai will receive these permits or approvals or we will reach a binding agreement with Kazatomprom or that Inkai will be able to ramp up production. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2012 and future annual production targets and we may have to recatagorize some of Inkai’s mineral reserves as resources.

We also require regulatory approval of our detailed block 3 delineation and test leach work programs.

Supply of sulphuric acid

There were brief interruptions to sulphuric acid supply during the year. Given the importance of sulphuric acid to Inkai’s mining operations, 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.

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

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

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

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    81

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

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

There has been recent civil unrest in the oil producing region of West Kazakhstan. The government has taken action to resolve the underlying concerns and restore stability. Inkai, which is in South Kazakhstan, has not been impacted by the civil unrest. We are monitoring the situation.

We also manage the risks listed on pages 62 to 64.

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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, 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: 2.25% 62.2 million pounds (inferred) average grade U3O8 : 12.59%
Mining method	jet boring
Target production date	begin commissioning in ore mid-2013; first packaged pounds in the fourth quarter of 2013
Target annual production (our share)	9 million pounds at full production
Estimated decommissioning cost	$27.7 million (to the end of construction)

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.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    83

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.

To meet our production schedule, the ground has to be fully frozen in the area being mined 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 per year. Two jet boring machines will be working at a time, while the other two are being moved or set up, or in the backfill cycle.

In the past, bulk freezing has been done from underground. In 2010, however, we tested and began to implement an innovative surface freeze strategy. The strategy reduces the risk to the production schedule for two reasons:

• the surface freeze process can start before developing the underground tunnels

• construction activities underground are simplified by moving some of the freezing infrastructure to surface

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. In 2011, we restarted freezing the ore from underground and used freezing around shaft 2 to support the sinking and subsequent break through on the 480 metre level. We also began to freeze the ground from surface.

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 is new to the uranium mining industry. It involves:

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• 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

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

• starting the process again with the next cavity

Milling

We have signed agreements with the owners of the Cigar Lake project and McClean Lake mill to process all Cigar Lake ore at McClean Lake.

Under the previous toll milling agreements, both the McClean Lake mill and the Rabbit Lake mill would process uranium from Cigar Lake. Under the new milling arrangement, the McClean Lake mill will process and package 100% of Cigar Lake uranium. The Rabbit Lake mill will continue to process ore mined on that site and has the flexibility to process ore from other potential sources.

2011 update

During the year, we:

• completed remediation of the underground

• resumed underground construction in the south end of the mine

• completed the sinking of shaft 2 to the 480 metre level in early 2012

• substantially completed the ore loadout facility

• procured additional equipment for the jet boring system

• obtained regulatory approval to change the discharge location for the release of treated water to Seru Bay of Waterbury Lake

• obtained regulatory approval for the Cigar Lake mine plan

Costs

As of December 31, 2011, we had:

• invested about $675 million for our share of the construction costs to develop Cigar Lake

• expensed about $86 million in remediation expenses, including about $4 million in 2011

• expensed about $35 million in standby costs

We expect to spend an additional $484 million (our share) to complete this project, which requires us to:

• invest about $429 million for our share of the remaining capital costs, bringing our total share to about $1.1 billion

• expense about $55 million for our share of the remaining standby costs, bringing our total share to about $90 million

This would bring our total share of the cost for this project to about $1.3 billion since we began development in 2005.

Exploration

We completed a surface drilling program this year, which increased the mineral reserves and average ore grade slightly, and extended the orebody further to the west. It also increased our confidence in the geology and the grade we can expect during the rampup period. We also initiated a drilling program to further delineate the west end of the mineralization.

Planning for the future

In 2012, we expect to:

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

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

• complete the surface ore loadout facility

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    85

• resume underground development in the north end of the mine

• move the jet boring system to site and begin testing underground

• develop two mining tunnels using the mine development system

• complete the Seru Bay pipeline

• complete all engineering designs and drawings for the project

• construct the clarifier

Technical report

Cigar Lake continues to be a key part of our plan to increase our annual production to 40 million pounds by 2018 and we are pleased with the progress we are making to bring this valuable orebody into production. Over the year, we implemented a number of changes to the project, which have enhanced the overall economics of the project. These changes have put Cigar Lake on the path to becoming another high-grade, low-cost source of production, similar to our McArthur River operation.

We are updating the March 2010 Cigar Lake technical report to reflect these changes, including the impact of the new milling arrangement, surface freezing and other developments. We plan to file the updated technical report with our February 2012 annual information form. The highlights of the technical report are:

• a decrease in the estimated average cash operating cost to about $18.60 per pound from about $23.10 per pound estimated in 2010. The reduction is primarily due to the new milling arrangement.

• an increase of about $190 million in our share of the total estimated capital cost at completion to $1.1 billion. The increase is mainly due to the implementation of the surface freeze strategy, general cost escalation, costs to upgrade and expand the McClean Lake mill and improvements to the mine plan.

• a change to the production profile, with slightly lower production expected in the first years of the project offset by higher production in the later years. We expect our share of production in 2013 to be about 0.3 million pounds. This compares to our previous estimate of 1 million pounds. This and the other revisions to our production schedule on page 65 represent an 8.7% decrease in our production forecast through 2016 and are a result of the extended period required for remediation and a better understanding of the geology and lower grades in the initial production panels.

• first commissioning in ore expected in mid-2013 and the first pounds expected to be packaged at the McClean Lake mill in the fourth quarter

• rampup to the full production rate expected by the end of 2017

• a 4% increase in our share of the mineral reserves estimate from 104.7 million pounds to 108.4 million pounds and an 8% increase in the estimated average ore grade

• an upgrade of probable mineral reserves to proven minerals reserves

Given the scale of this project and the challenging nature of the geology and mining method, we have made significant achievements since 2010. We will continue to develop this asset in a safe and deliberate manner to ensure we realize the economic benefits of this project.

Our expectations and plans regarding Cigar Lake, the expected benefit of milling Cigar Lake ore at the McClean Lake mill, the estimated average cash operating cost, our expected share of the total project and capital cost at completion for Cigar Lake and our mineral reserve estimate, are forward-looking information. They are based on the assumptions and subject to the material risks discussed on page 3, and specifically on the assumptions and risks listed on the following page.

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Assumptions

• our expectation that the new milling arrangement will result in the expected reduction in the operating cost

• there is no material delay or disruption in our plans as a result of a 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

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

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

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

• our Cigar Lake development, mining and production plans succeed

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

Material risks

• the new milling arrangement does not result in the expected cost savings or other benefits

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

• ground movements or cave ins

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

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

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

• our mineral reserves estimate is not reliable

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

Managing our risks

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

Water inflow risk

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

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

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

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

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

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

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

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    87

Jet boring mining method and units

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

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

We also manage the risks listed on pages 62 to 64.

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Uranium – projects under evaluation

Kintyre

Kintyre, which we acquired with a partner in 2008, diversifies our geographic reach and deposit types. We are the operator.

Location	Western Australia
Ownership	70%
End product	uranium concentrates
Mine type	open pit
Estimated resources (our share)	38.7 million pounds (indicated) average grade U3O8: 0.58% 6.7 million pounds (inferred) average grade U3O8 : 0.46%

Background

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

2011 update

This year we:

• generated a National Instrument 43-101 mineral resource estimate

• completed an MOU for a mine development agreement with the Martu

• significantly advanced a prefeasibility study and an environmental review and management program, the level of environmental assessment required for the Kintyre project

We had planned to complete the prefeasibility study and submit a draft environmental review and management program. To support the prefeasibility study, we expanded the scope of our drilling program and have delayed these activities to 2012.

Planning for the future

Our plan for 2012 is to keep moving the project towards a production decision. We expect to:

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

• complete the prefeasibility study and decide whether to proceed to the feasibility stage

• submit a draft environmental review and management program

• complete the mine development agreement with the Martu

Managing the risks

To successfully develop this project, we need a positive feasibility study, regulatory approval and an agreement with the Martu. We also manage the risks listed on pages 62 to 64.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    89

Uranium – projects under evaluation

Millennium

Millennium is a uranium deposit in northern Saskatchewan that we expect will use our excess milling capacity. We are the operator.

Location	Saskatchewan, Canada
Ownership	42%
End product	uranium concentrates
Mine type	underground
Estimated resources (our share)	21.4 million pounds (indicated) average grade U3O8: 4.55% 7.0 million pounds (inferred) average grade U3O8 : 2.54%

Background

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

2011 update

This year we:

• continued work on the environmental assessment

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

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

Planning for the future

Our plan for 2012 is to keep moving the project towards a production decision. We expect to:

• complete the environmental assessment and submit the draft environmental impact study to the regulators in early 2012

• begin engineering for the project

• carry out a drill program to test the upper portion of the ore body

Managing our risks

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

Environment Canada has proposed a recovery strategy for woodland caribou in northern Saskatchewan. This strategy has the potential to restrict further economic and social development in northern Saskatchewan and could have an impact on our ability to develop this deposit.

We also manage the risks listed on pages 62 to 64.

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Uranium – exploration

Exploration is key to ensuring our long-term growth, and since 2007 we have more than doubled our annual investment.

2011 update

Brownfield exploration

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

This year we spent $10 million on five brownfield exploration projects, and $38 million for resource definition at Kintyre and at Cigar Lake.

Regional exploration

We spent about $48 million on regional exploration programs (including support costs). Saskatchewan was the largest region, followed by Australia, northern Canada, Asia and South America.

Plans for 2012

We plan to spend approximately $115 million on uranium exploration in 2012 as part of our long-term strategy.

Brownfield exploration

We plan to spend approximately $15 million on five brownfield exploration projects in the Athabasca Basin and Australia. Our expenditures on projects under evaluation are expected to total $35 million, with the largest amounts spent on Kintyre and Inkai block 3.

Regional exploration

We plan to spend about $65 million on 49 projects worldwide, the majority of which are at drill target stage. Among the larger expenditures planned are $9 million on two adjacent projects in Nunavut, $9 million to test targets near our US operations and on our satellite properties, $4 million on the Read Lake project, $5 million on targets in South Australia, and $5 million to follow up encouraging results on the Wellington Range project in Australia.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    91

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	approved: 18 million kgU as UO3 per year application: 24 million kgU as UO3 per year
Estimated decommissioning cost	$38.6 million (pending regulatory approval)

2011 update

Production

Our Blind River refinery produced 13.5 million kgU of UO₃ this year. This ensured that SFL maintained its contractual inventories and Port Hope met its production requirements.

Managing our risks

We manage the risks listed on pages 62 to 64.

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Fuel services – conversion and fuel manufacturing

We control about 25% of world UF₆ conversion capacity.

Port Hope conversion services

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

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	$101.7 million (pending regulatory approval)

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	$19.5 million (pending regulatory approval)

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

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    93

2011 update

Production

Fuel services produced 14.7 million kgU in 2011, slightly lower than our plan at the beginning of the year and 5% lower than 2010. In the third quarter, we reduced our production due to unfavourable market conditions for UF₆ conversion.

Port Hope conversion facility cleanup and modernization (Vision 2010)

We submitted the draft environmental impact statement for review by the regulators in December 2010 and have continued work on the environmental assessment.

Community outreach

We continued to strengthen our community outreach program in Port Hope by:

• holding a series of community forums

• making presentations to municipal council

• reaching out using community newsletters, newspaper advertising, public displays, open houses and a website dedicated to the Port Hope community

Public opinion research shows we have strong local support.

Springfields toll milling agreement

Based on the unfavourable market conditions for UF₆ conversion, we have discontinued discussions to extend our toll conversion contract with SFL beyond 2016. We remain fully committed to the current contract. If market conditions improve over the next few years, we would consider resuming our discussions to extend the contract.

Planning for the future

Production

We have lowered our production target for 2012 to between 13 million and 14 million kgU due to the unfavourable market conditions for UF₆ conversion.

Port Hope conversion facility cleanup and modernization (Vision 2010)

In 2012, we expect to continue with the environmental assessment process for this project.

Managing our risks

We manage the risks listed on pages 62 to 64.

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Electricity

Bruce Power Limited Partnership (BPLP)

BPLP leases and operates four Candu nuclear reactors that have the capacity to provide about 18% of Ontario’s electricity.

Location	Ontario, Canada
Ownership	31.6%
ISO certification	ISO 14001 certified
Expected reactor life	2018 to 2021
Term of lease	2018 – right to extend for up to 25 years
Generation capacity	3,260 MW

Background

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

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

2011 update

Output

BPLP’s capacity factor was 87%.

Collective agreements

The collective agreements with the Power Workers’ Union and the Society of Energy Professionals expired in December 2010. BPLP reached an agreement with the Power Workers’ Union this year for a new contract that extends to 2013, and with the Society of Energy Professionals for a new contract that extends until 2014.

Planning for the future

Output

We expect the capacity factor to be 95% in 2012 and actual output to be about 9% higher than 2011.

Managing our risks

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

BPLP also manages the risks listed on pages 62 to 64.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    95

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.

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 $58.00 (US) per pound U₃O₈ unless otherwise noted, 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.

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. Metallurgical recovery is an estimate of the amount of valuable product that can be physically recovered by the metallurgical extraction process, and is calculated by multiplying the quantity of contained metal (content) by the estimated metallurgical recovery percentage. Our share of uranium in the mineral reserves table on page 99 is before accounting for estimated metallurgical recovery.

Changes this year

Our share of proven and probable mineral reserves went from 476 million pounds U₃O₈ at the end of 2010 to 435 million pounds at the end of 2011. The change was mostly the result of:

• mining and milling activities, which used 23.4 million pounds

• conversion of probable mineral reserves to proven from additional drilling results and/or refinements to the mining and freezing plans at McArthur River and Cigar Lake

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• conversion of mineral reserves to mineral resources for portions of Gas Hills-Peach and North Butte-Brown Ranch where it was recognized that the project risks and economic assessments could be improved by modelling individual roll-fronts instead of combining them as one mineralized unit

• At Inkai, a requirement to produce equal amounts from blocks 1 and 2 resulted in an update of the life-of-mine production schedule and conversion of pounds from reserves to resources

Measured and indicated mineral resources increased from 142 million pounds U₃O₈ at the end of 2010 to 254 million pounds at the end of 2011. The change was mostly the result of:

• first time reporting of mineral resources at Kintyre

• conversion of inferred mineral resources to indicated resources at McArthur River

• conversion of mineral reserves to mineral resources at Gas Hills-Peach and Inkai

At the end of 2011, our share of inferred mineral resources was 318 million pounds U₃O₈ — a net decrease of 39 million pounds, which were mostly upgraded to the indicated resource category at McArthur River zone B and Cigar Lake.

Qualified persons

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

McArthur River/Key Lake

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

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

• Greg Murdock, technical superintendent, McArthur River, Cameco

• Les Yesnik, general manager, Key Lake, Cameco

Cigar Lake

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

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

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

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

Inkai

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

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

• Lawrence Reimann, manager, technical services, Cameco Resources

Important information about mineral reserve and resource estimates

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

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

• geological interpretation

• extraction plans

• commodity prices and currency exchange rates

• recovery rates

• operating and capital costs

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

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    97

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, 2011 (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)		Estimated metallurgical recovery (%)
McArthur River	underground		457.5		22.07		222.6		412.7		11.14		101.4		870.2		16.89		324.0		226.2		98.7
Cigar Lake	underground		233.6		22.31		114.9		303.5		15.22		101.8		537.1		18.30		216.7		108.4		98.5
Rabbit Lake	underground		91.0		0.52		1.0		1,399.9		0.75		23.0		1,490.9		0.73		24.0		24.0		96.7
Key Lake	open pit		61.9		0.52		0.7								61.9		0.52		0.7		0.6		98.7
Inkai	ISR		3,772.4		0.08		6.9		63,692.4		0.07		92.6		67,464.8		0.07		99.5		59.7		85.0
Gas Hills-Peach	ISR								999.2		0.11		2.4		999.2		0.11		2.4		2.4		72.0
North Butte-Brown Ranch	ISR								1,839.3		0.09		3.7		1,839.3		0.09		3.7		3.7		80.0
Smith Ranch-Highland	ISR		1,124.7		0.11		2.7		2,263.4		0.08		3.9		3,388.1		0.09		6.6		6.6		80.0
Crow Butte	ISR		1,282.6		0.13		3.7								1,282.6		0.13		3.7		3.7		85.0
Total			7,023.7		—		352.5		70,910.4		—		328.8		77,934.1		—		681.3		435.3

Notes

ISR – in situ recovery

Estimates in the table above:

• use an average uranium price of $58.00 (US)/lb U₃O₈ except for Cigar Lake which uses an average uranium price of $61.00 (US)/lb U₃O₈

• are based on an average exchange rate of $1.00 US=$1.02 Cdn, except Cigar Lake, which is based on an average exchange rate of $1.00 US=$1.10 Cdn

Totals may not add up due to rounding.

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

Metallurgical recovery

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

Estimates for Inkai

Our 2012 and future annual production targets and mineral estimate for Inkai assume, and we expect:

• Inkai will obtain the necessary government permits and approvals to produce at an annual rate of 5.2 million pounds (100% basis), including an amendment to the resource use contract

• we reach a binding agreement with Kazatomprom to finalize the terms of the MOA

• Inkai will ramp up production to an annual rate of 5.2 million pounds (100% basis)

There is no certainty Inkai will receive these permits or approvals or we will reach a binding agreement with Kazatomprom or that Inkai will be able to ramp up production. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2012 and future annual production targets and we may have to recatagorize some of Inkai’s reserves as resources.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    99

Mineral resources

As at December 31, 2011 (100% – 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)
McArthur River	underground		73.7		5.58		9.1		114.4		25.40		64.0		188.1		17.63		73.1		51.0
Cigar Lake	underground		18.9		1.68		0.7		25.5		2.71		1.5		44.4		2.25		2.2		1.1
Kintyre	open pit								4,315.4		0.58		55.2		4,315.4		0.58		55.2		38.7
Rabbit Lake	underground								362.4		0.53		4.3		362.4		0.53		4.3		4.3
Dawn Lake	open pit, underground								347.0		1.69		12.9		347.0		1.69		12.9		7.4
Millennium	underground								507.8		4.55		50.9		507.8		4.55		50.9		21.4
Phoenix	underground								89.9		17.98		35.6		89.9		17.98		35.6		10.7
Tamarack	underground								183.8		4.42		17.9		183.8		4.42		17.9		10.3
Inkai	ISR								28,613.1		0.08		48.0		28,613.1		0.08		48.0		28.8
Gas Hills-Peach	ISR		1,964.2		0.08		3.4		7,821.9		0.11		18.8		9,786.1		0.10		22.2		22.2
North Butte-Brown Ranch	ISR								7,248.9		0.08		12.3		7,248.9		0.08		12.3		12.3
Smith Ranch-Highland	ISR		2,158.3		0.11		5.1		14,778.0		0.06		18.6		16,936.3		0.06		23.7		23.7
Crow Butte	ISR								2,592.2		0.21		11.9		2,592.2		0.21		11.9		11.9
Ruby Ranch	ISR								2,215.3		0.08		4.1		2,215.3		0.08		4.1		4.1
Ruth	ISR								1,080.5		0.09		2.1		1,080.5		0.09		2.1		2.1
Shirley Basin	ISR		89.2		0.16		0.3		1,638.2		0.11		4.1		1,727.4		0.12		4.4		4.4
Total			4,304.3		—		18.6		71,934.3		—		362.2		76,238.6		—		380.8		254.4

Inferred (tonnes in thousands; pounds in millions)

Property	Mining method	Tonnes		Grade % U3O8		Content (lbs U3O8)		Cameco’s share (lbs  U3O8)
McArthur River	underground		405.2		9.67		86.4		60.3
Cigar Lake	underground		448.0		12.59		124.4		62.2
Kintyre	open pit		950.2		0.46		9.6		6.7
Rabbit Lake	underground		331.9		1.42		10.4		10.4
Millennium	underground		297.8		2.54		16.7		7.0
Phoenix	underground		23.8		7.27		3.8		1.1
Tamarack	underground		45.6		1.02		1.0		0.6
Inkai	ISR		254,696.0		0.05		255.1		153.0
Gas Hills-Peach	ISR		861.5		0.07		1.3		1.3
North Butte-Brown Ranch	ISR		594.3		0.06		0.8		0.8
Smith Ranch-Highland	ISR		6,404.0		0.05		6.6		6.6
Crow Butte	ISR		2,282.2		0.12		6.0		6.0
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			268,115.6		—		523.8		317.7

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.

100    CAMECO CORPORATION

Additional information

Related party transactions

We buy significant amounts of goods and services for our Saskatchewan mining operations from northern Saskatchewan suppliers to support economic development in the region. One of these suppliers is Points Athabasca Contracting Ltd. (PACL). In 2011, we paid PACL $63 million for construction and contracting services (2010 – $38 million). These transactions were carried out in the normal course of business. A member of Cameco’s board of directors is the president of PACL.

Critical accounting estimates

Because of the nature of our business, we are required to make estimates that affect the amount of assets and liabilities, revenues and expenses, commitments and contingencies we report.

We base our estimates on our experience, our best judgment, guidelines established by the Canadian Institute of Mining, Metallurgy and Petroleum and on assumptions we believe are reasonable. We believe the following critical accounting estimates reflect the more significant judgments used in the preparation of our financial statements.

Decommissioning and reclamation

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

Property, plant and equipment

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

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

Taxes

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

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

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    101

Controls and procedures

We have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2011, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.

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

Management, including our CEO and our CFO, is responsible for establishing and maintaining internal control over financial reporting and conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2011. We have not made any change to our internal control over financial reporting during the 2011 fiscal year that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

New accounting pronouncements

Financial instruments

In October 2010, the International Accounting Standards Board (“IASB”) issued IFRS 9, Financial Instruments (“IFRS 9”). This standard is effective for periods beginning on or after January 1, 2015 and is part of a wider project to replace IAS 39, Financial Instruments: Recognition and Measurement. IFRS 9 replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The basis of classification depends on the entity’s business model and the contractual cash flow characteristics of the financial asset or liability. The guidance in IAS 39 on impairment of financial assets and hedge accounting continues to apply. We are assessing the impact of this new standard on our financial statements.

Consolidated financial statements

In May 2011, the IASB issued IFRS 10, Consolidated Financial Statements (“IFRS 10”). This standard is effective for periods beginning on or after January 1, 2013 and establishes principles for the presentation and preparation of consolidated financial statements when an entity controls one or more other entities. IFRS 10 defines the principle of control and establishes control as the basis for determining which entities are consolidated in the consolidated financial statements. We are assessing the impact of this new standard on our financial statements.

Joint arrangements

In May 2011, the IASB issued IFRS 11, Joint Arrangements (“IFRS 11”). This standard is effective for periods beginning on or after January 1, 2013 and establishes principles for financial reporting by parties to a joint arrangement. IFRS 11 requires a party to assess the rights and obligations arising from an arrangement in determining whether an arrangement is either a joint venture or a joint operation. Joint ventures are to be accounted for using the equity method while joint operations will continue to be accounted for using proportionate consolidation. We are assessing the impact of this new standard on our financial statements.

102    CAMECO CORPORATION

Disclosure of interests in other entities

In May 2011, the IASB issued IFRS 12, Disclosure of Interests in Other Entities (“IFRS 12”). This standard is effective for periods beginning on or after January 1, 2013 and applies to entities that have an interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. IFRS 12 integrates and makes consistent the disclosure requirements for a reporting entity’s interest in other entities and presents those requirements in a single standard. We are assessing the impact of this new standard on our financial statements.

Fair value measurement

In May 2011, the IASB issued IFRS 13, Fair Value Measurement (“IFRS 13”). This standard is effective for periods beginning on or after January 1, 2013 and provides additional guidance where IFRS requires fair value to be used. IFRS 13 defines fair value, sets out in a single standard a framework for measuring fair value and establishes the required disclosures about fair value measurements. We are assessing the impact of this new standard on our financial statements.

Employee benefits

In June 2011, the IASB issued an amended version of IAS 19, Employee Benefits (“IAS 19”). This amendment is effective for periods beginning on or after January 1, 2013 and eliminates the ‘corridor method’ of accounting for defined benefit plans. Revised IAS 19 also streamlines the presentation of changes in assets and liabilities arising from defined benefit plans, and enhances the disclosure requirements for defined benefit plans. We are assessing the impact of this revised standard on our financial statements.

Presentation of other comprehensive income (OCI)

In June 2011, the IASB issued an amended version of IAS 1, Presentation of Financial Statements (“IAS 1”). This amendment is effective for periods beginning on or after January 1, 2012 and requires companies preparing financial statements in accordance with IFRS to group together items within OCI that may be reclassified to the profit or loss section of the statement of earnings. Revised IAS 1 also reaffirms existing requirements that items in OCI and profit or loss should be presented as either a single statement or two consecutive statements. We are assessing the impact of this revised standard on our financial statements.

2011 MANAGEMENT’S DISCUSSION AND ANALYSIS    103

EX-99.4

EXHIBIT 99.4

For fiscal years ended December 31, 2011 and December 31, 2010, KPMG LLP and its affiliates were paid by Cameco Corporation and its subsidiaries the following fees:

(Cdn$)	2011		% of Total Fees			2010		% of Total Fees
Audit Fees:
Cameco	$	1,773,600		61.4	%	$	1,697,700		62.6	%
Subsidiaries		400,700		13.9	%		256,200		9.5	%
Total Audit Fees	$	2,174,300		75.3	%	$	1,953,900		72.1	%
Audit-Related Fees:
Translation services		—		—		$	44,500		1.7	%
Accounting advisory	$	195,100		6.8	%		273,400		10.1	%
Pensions and other		21,000		0.7	%		20,000		0.7	%
Total Audit-Related Fees	$	216,100		7.5	%	$	337,900		12.5	%
Tax Fees:
Compliance	$	62,500		2.2	%	$	199,200		7.3	%
Planning and advice		433,400		15.0	%		219,500		8.1	%
Total Tax Fees	$	495,900		17.2	%	$	418,700		15.4	%
All Other Fees:		—		—			—		—
Total Fees:	$	2,886,300		100.0	%	$	2,710,500		100.0	%

Pre-Approval Policies and Procedures

As part of Cameco Corporation’s corporate governance practices, under its audit committee charter, the audit committee is required to pre-approve the audit and non-audit services performed by the external auditors. The audit 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 committee or audit committee chair, or in the absence of the audit 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 committee at its next meeting. The audit committee has adopted a written policy to provide procedures to implement the foregoing principles. For each of the years ended December 31, 2011 and 2010, 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, 2011 (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		801		—		6		299		496
BPLP capital lease		146		15		35		43		53
Interest on long-term debt		270		43		85		67		76
Interest on BPLP capital lease		43		10		17		11		4
Provision for reclamation		577		10		40		47		480
Provision for waste disposal		22		4		7		11		—
Other liabilities		507		—		—		—		507
Unconditional product purchase commitments 1, 2		1,457		308		581		128		440
Total contractual cash obligations		3,823		390		771		606		2,056

¹  Denominated in US dollars. Converted to Canadian dollars at the December 31, 2011 rate of Cdn $1.017.

²  Virtually all of Cameco Corporation’s product purchase obligations are under long-term, fixed-price arrangements.

Commercial Commitments

As at December 31, 2011 (Cdn$ millions)	Total amounts committed
Standby letters of credit 1		670
BPLP guarantees 2		69
Total commercial commitments		739

¹ The standby letters of credit maturing in 2012 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, 2011, Cameco Corporation’s total commitment for financial assurances given on behalf of BPLP was estimated to be Cdn $77 million. Refer to note 31 in the 2011 consolidated audited financial statements.

EX-99.6

EXHIBIT 99.6

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Cameco Corporation

We have audited Cameco Corporation’s internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control – Integrated Framework 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, 2011, based on the criteria established in Internal Control – Integrated Framework 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 as of December 31, 2011, December 31, 2010 and January 1, 2010, and the related consolidated statements of earnings, comprehensive income, changes in equity and cash flows for the years ended December 31, 2011 and December 31, 2010, and our report dated February 8, 2012 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Chartered Accountants

Saskatoon, Canada

February 8, 2012

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, 2011, December 31, 2010 and January 1, 2010 and the related consolidated statements of earnings, comprehensive income, changes in equity and cash flows for the years ended December 31, 2011 and December 31, 2010. 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, 2011, December 31, 2010 and January 1, 2010, and its consolidated financial performance and its consolidated cash flows for the years ended December 31, 2011 and December 31, 2010 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, 2011, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 8, 2012 expressed an unqualified opinion on the effectiveness of Cameco Corporation’s internal control over financial reporting.

/s/ KPMG LLP

Chartered Accountants

Saskatoon, Canada

February 8, 2012

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 inclusion in this annual report on Form 40-F of:

• our auditors’ report dated February 8, 2012 on the consolidated financial statements of Cameco Corporation (the “Corporation”), which comprise the consolidated statements of financial position as at December 31, 2011, December 31, 2010 and January 1, 2010, the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for the years ended December 31, 2011 and December 31, 2010, and notes, comprising a summary of significant accounting policies and other explanatory information,

• our Report of Independent Registered Public Accounting Firm dated February 8, 2012 in accordance with the standards of the Public Company Accounting Oversight Board (United States), and

• our Report of Independent Registered Public Accounting Firm dated February 8, 2012 on the Corporation’s internal control over financial reporting as of December 31, 2011,

each of which is contained in this annual report on Form 40-F of the Corporation for the fiscal year ended December 31, 2011.

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, and registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan.

/s/ KPMG LLP

Chartered Accountants

Saskatoon, Canada

February 24, 2012

EX-99.9

EXHIBIT 99.9

I, Tim S. 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 24, 2012

/s/ Tim S. Gitzel
Name:	Tim S. Gitzel
Title:	President & Chief Executive Officer (Principal Executive Officer)

EX-99.10

EXHIBIT 99.10

I, Grant E. 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 24, 2012

/s/ Grant E. Isaac
Name:	Grant E. Isaac
Title:	Senior Vice-President & 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, 2011, as filed with the U.S. Securities and Exchange Commission on the date hereof (the “Report”), I, Tim S. Gitzel, President & 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 S. Gitzel
	Name: Tim S. Gitzel
	Title: President & Chief Executive Officer

February 24, 2012

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, 2011, as filed with the U.S. Securities and Exchange Commission on the date hereof (the “Report”), I, Grant E. Isaac, Senior Vice-President & 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 E. Isaac
	Name: Grant E. Isaac
	Title: Senior Vice-President & Chief Financial Officer

February 24, 2012

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, 2011 dated February 24, 2012 for the McArthur River/Key Lake, Inkai and Cigar Lake properties; and

(b) under the heading “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2011 dated February 9, 2012 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, and registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan.

Sincerely,

/s/ Alain G. Mainville
Name:	Alain G. Mainville, P. Geo.
Title:	Director, Mineral Resources Management, Cameco Corporation
Date: February 24, 2012

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, 2011 dated February 24, 2012 for the Inkai property; and

(b) under the heading “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2011 dated February 9, 2012 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, and registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan.

Sincerely,

/s/ Dave Neuburger
Name:	Dave Neuburger, P. Eng.
Title:	Vice-President, International Mining, Cameco Corporation
Date: February 24, 2012

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, 2011 dated February 24, 2012 for the Inkai property; and

(b) under the heading “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2011 dated February 9, 2012 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, and registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan.

Sincerely,

/s/ Lawrence Reimann
Name:	Lawrence Reimann, P. Eng.
Title:	Manager, Technical Services, Power Resources, Inc. (operating as Cameco Resources)
Date:	February 24, 2012

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, 2011 dated February 24, 2012 for the Cigar Lake property; and

(b) under the heading “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2011 dated February 9, 2012 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, and registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan.

Sincerely,

/s/ Grant J. H. Goddard
Name:	Grant J. H. Goddard, P. Eng.
Title:	Vice-President, Saskatchewan Mining North, Cameco Corporation
Date:	February 24, 2012

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, 2011 dated February 24, 2012 for the Cigar Lake property; and

(b) under the heading “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2011 dated February 9, 2012 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, and registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan.

Sincerely,

/s/ Eric Paulsen
Name:	Eric Paulsen, P. Eng., Pr. Eng.
Title:	Interim Chief Metallurgist, Cameco Technology and Innovation, Cameco Corporation
Date:	February 24, 2012

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 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, 2011 dated February 24, 2012 for the Cigar Lake property; and

(b) under the heading “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2011 dated February 9, 2012 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, and registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan.

Sincerely,

/s/ C. Scott Bishop
Name:	C. Scott Bishop, P. Eng.
Title:	Principal Mine Engineer, Cameco Technology and Innovation, Cameco Corporation
Date:	February 24, 2012

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, 2011 dated February 24, 2012 for the McArthur River/Key Lake properties; and

(b) under the heading “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2011 dated February 9, 2012 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, and registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan.

Sincerely,

/s/ Gregory M. Murdock
Name:	Gregory M. Murdock, P. Eng.
Title:	Technical Superintendent, McArthur River, Cameco Corporation
Date:	February 24, 2012

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, 2011 dated February 24, 2012 for the McArthur River/Key Lake properties; and

(b) under the heading “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2011 dated February 9, 2012 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, and registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan.

Sincerely,

/s/ David Bronkhorst
Name:	David Bronkhorst, P. Eng.
Title:	Vice-President, Saskatchewan Mining South, Cameco Corporation
Date:	February 24, 2012

EX-99.21

EXHIBIT 99.21

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, 2011 dated February 24, 2012 for the McArthur River/Key Lake properties; and

(b) under the heading “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2011 dated February 9, 2012 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, and registration statement (No. 333-139324) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan.

Sincerely,
/s/ Leslie (Les) D. Yesnik
Name:	Leslie (Les) D. Yesnik, P. Eng.
Title:	General Manager, Key Lake operations, Cameco Corporation
Date:	February 24, 2012