CCJ Cameco Corporation

 

 

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, 2014

Commission file number: 1-14228

 

 

CAMECO CORPORATION

(Exact name of Registrant as specified in its charter)

 

 

CANADA

(Province or other jurisdiction of incorporation or organization)

1090

(Primary Standard Industrial Classification Code Number)

98-0113090

(I.R.S. Employer Identification)

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

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

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

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

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

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

Title of Class: Common Shares, no par value

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

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

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

Information filed with this Form:

 

x  Annual Information Form		x  Audited annual financial statements

Number of outstanding shares of each of the issuer’s classes of

capital or common stock as of the close of the period covered by the annual report:

395,792,522 Common Shares outstanding as of December 31, 2014

 

 

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”.

 

 

 

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Certifications and Disclosure Regarding Controls and Procedures.

 

(a)

Certifications regarding controls and procedures. See Exhibits 99.9 and 99.10.

 

(b)

Evaluation of disclosure controls and procedures. As of December 31, 2014 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 (2013) 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, 2014.

 

(d)

Attestation report of the registered public accounting firm. The effectiveness of Cameco Corporation’s internal control over financial reporting as of December 31, 2014 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, 2014, there were no changes in Cameco Corporation’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, Cameco Corporation’s internal control over financial reporting.

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

 

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

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

Code of Ethics. Cameco Corporation’s code of conduct and ethics (the “Code”) is applicable to all directors, officers and employees of Cameco Corporation, including the CEO and CFO. The Code, as well as Cameco Corporation’s corporate governance practices and mandates of the board of directors and its committees, and position descriptions for the chief executive officer and the non-executive chair, can be found on Cameco Corporation’s website at www.cameco.com under “About – Governance” and are also available in print to any shareholder upon request. Since the adoption of the Code, there have not been any waivers, including implied waivers, from any provision of the Code. In 2014, we amended our previously filed Code to provide for:

 

•

updates to pictures, titles and telephone numbers; and

 

•

modifying the group of employees that need to provide an annual confirmation.

The Code was furnished to the Commission on February 4, 2015 as Exhibit 1 to a report on Form 6-K and is incorporated by reference herein as Exhibit 99.22.

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, as well as terms under certain financing arrangements at its subsidiary, NUKEM Energy GmbH (NUKEM). These arrangements are disclosed in the following sections of Exhibit 99.3 – 2014 Management’s Discussion and Analysis and the notes to the financial statements in Exhibit No 99.2 – 2014 Consolidated Audited Financial Statements:

 

(a)

Financial assurances. In the 2014 Management’s Discussion and Analysis, see the disclosure at “Off-balance sheet arrangements” (page 38). In the 2014 Consolidated Audited Financial Statements, see the disclosure at note 16 of the financial statements.

 

(b)

Long-term product purchase contracts. In the 2014 Management’s Discussion and Analysis, see the disclosure at “Off-balance sheet arrangements” (page 38).

 

(c)

NUKEM financing arrangements. In the 2014 Management’s Discussion and Analysis, see the disclosure at “NUKEM financing arrangement” (page 38). In the 2014 Consolidated Audited Financial Statements, see the disclosure at note 9 to the financial statements.

 

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Tabular Disclosure of Contractual Obligations. See Exhibit 99.5.

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

Audited Annual Financial Statements. Cameco Corporation’s Consolidated Audited Financial Statements as at December 31, 2014 and 2013, including the related report of the independent registered public accounting firm, is included in Exhibit 99.7 – Report of Independent Registered Public Accounting Firm – Public Company Accounting Oversight Board (United States) Standards.

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

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

 

(a)

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

 

(b)

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

 

4

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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 “About – 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: Ian Bruce; Daniel Camus; John Clappison; Joe Colvin; James Curtiss; Donald Deranger; Catherine Gignac; James Gowans; Nancy Hopkins; Anne McLellan; Neil McMillan; and Victor Zaleschuk. Each of the non-management directors is “independent”, as such term is used in the rules of the NYSE with the exception of Donald Deranger and John Clappison.

 

(f)

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

 

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EXHIBIT INDEX

 

Exhibit No.		Description
99.1		2014 Annual Information Form
99.2		2014 Consolidated Audited Financial Statements
99.3		2014 Management’s Discussion and Analysis
99.4		Principal Accountant Fees and Services
99.5		Tabular Disclosure of Contractual Obligations
99.6		Report of Independent Registered Public Accounting Firm – Internal Control Over Financial Reporting
99.7		Report of Independent Registered Public Accounting Firm – Public Company Accounting Oversight Board (United States) Standards
99.8		Consent of Independent Registered Public Accounting Firm
99.9		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the U.S. Securities Exchange Act of 1934, as amended
99.10		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the U.S. Securities Exchange Act of 1934, as amended
99.11		Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.12		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.13		Consent of Alain G. Mainville, P. Geo.
99.14		Consent of Eric Paulsen, P. Eng., Pr. Eng.
99.15		Consent of C. Scott Bishop, P. Eng.

 

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99.16		Consent of Darryl Clark, P. Geo.
99.17		Consent of Lawrence Reimann, P. Eng.
99.18		Consent of Brian Soliz, P. Geo.
99.19		Consent of Baoyao Tang, P. Eng.
99.20		Consent of David Bronkhorst, P. Eng.
99.21		Consent of Leslie (Les) D. Yesnik, P. Eng.
99.22		Code of Conduct and Ethics (as amended and restated as of October 2014) (incorporated by reference to Cameco Corporation’s Form 6-K, furnished to the Commission on February 4, 2015)

 

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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 6^th day of March, 2015.

 

 

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EXHIBIT 99.1

Cameco Corporation

2014 Annual Information Form

March 6, 2015

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Cameco Corporation

2014 Annual information form

March 6, 2015

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Contents

 

Important information about this document			1
About Cameco			4
Operations and projects			14
Uranium – operating properties			15
Uranium – projects under evaluation			59
Fuel services – refining			63
Fuel services – conversion and fuel manufacturing			64
NUKEM GmbH			66
Mineral reserves and resources			67
Sustainable development			75
The regulatory environment			85
Risks that can affect our business			94
Legal proceedings			113
Investor information			114
Governance			120
Appendix A			125

 

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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 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:

 

 

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

Reporting currency and financial information

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

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

Caution about forward-looking information

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

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

 

•

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

 

•

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

 

•

Actual results and events may be significantly different from what we currently expect, because of the risks associated with our business. We list a number of these material risks below. We recommend you also review other parts of this document, including Risks that can affect our business starting on page 94, and our 2014 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.

 

2014 ANNUAL INFORMATION FORM    Page 1

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Examples of forward-looking information in this AIF

 

 

Material risks

 

 

2014 ANNUAL INFORMATION FORM    Page 2

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Material assumptions

 

 

2014 ANNUAL INFORMATION FORM    Page 3

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About Cameco

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

Strategy

 

 

Business segments

URANIUM

 

 

2014 ANNUAL INFORMATION FORM    Page 4

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FUEL SERVICES

 

 

NUKEM

 

 

For information about our revenue and gross profit by business segment for the years ended December 31, 2014 and 2013, see our 2014 MD&A as follows:

 

•

uranium – page 40

 

•

fuel services – page 42

 

•

NUKEM – page 42.

 

Other fuel cycle investments

ENRICHMENT

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

Having operational control of both uranium production and enrichment facilities would offer operational synergies that could significantly enhance profit margins.

 

2014 ANNUAL INFORMATION FORM    Page 5

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The nuclear fuel cycle

 

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

 

 

2014 ANNUAL INFORMATION FORM    Page 6

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Major developments

 

 

2014 ANNUAL INFORMATION FORM    Page 7

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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 115 and 116.

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 three main subsidiaries:

 

 

2014 ANNUAL INFORMATION FORM    Page 8

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Our markets

 

Demand

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

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

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

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

Overall, the anticipated increase in nuclear plants from 437 (representing 398 gigawatts) today to 518 (representing 505 gigawatts) by 2024 illustrates a promising growth picture.

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

World annual uranium fuel consumption has increased from 75 million pounds U₃O₈ in 1980 to an estimated 155 million pounds in 2014. We expect global uranium consumption to increase to about 165 million pounds in 2015 and global production to be approximately 155 million pounds.

Over the next decade, we expect world demand to grow at an average annual growth rate of about 4%, totaling approximately 2.2 billion pounds from 2015-2024. As a result of that growth, by 2024, we expect annual world consumption to be approximately 230 million pounds.

 

2014 ANNUAL INFORMATION FORM    Page 9

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

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

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

Supply

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

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

 

•

approximately 70% of global uranium supply to come from existing primary production

 

•

approximately 15% will come from existing secondary supply sources

 

•

approximately 15% 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 bringing on and ramping up production can take between seven and 10 years. Many producers have announced delays and cancellations to their projects, which could have an effect on the longer term outlook for the uranium industry. Complicating the supply outlook further is the possibility of some projects, primarily driven by sovereign interests, moving forward in the near term despite market conditions.

We expect existing primary production to decrease over the next decade, falling to 140 million pounds by 2024 and highlighting the need for new primary supply.

We estimate world mine production in 2014 was about 147 million pounds U₃O₈, down 5% from 154 million pounds in 2013:

 

•

92% of the estimated world production came from eight countries: Kazakhstan (41%), Canada (16%), Australia (9%), Niger (8%), Namibia (5%), Russia (5%), Uzbekistan (4%), and the US (4%)

 

•

70% of the estimated world production was marketed by five producers. We accounted for about 16% of that production (23.3 million pounds).

Secondary sources

Uranium consumption has outstripped uranium production every year since 1985.

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

 

•

Uranium from dismantled Russian nuclear weapons was the largest source of secondary supply. Deliveries from this source ended in 2013.

 

•

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

 

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

 

•

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

Uranium from nuclear disarmament

Trade restraints and policies

The importation of Russian uranium into the US market is regulated by the amended USEC Privatization Act and by the Agreement Suspending the Antidumping Action against Russian Uranium Products (the Russian Suspension Agreement), which together impose annual quotas of approximately 12-13 million pounds U₃O₈ equivalent on imports of Russian uranium. These quotas on Russian uranium, expressed in kgU as LEU and administered by the US Department of Commerce, were set at the equivalent of 20% of annual US reactor demand and are scheduled to expire at the end of 2020.

The US has regulated the importation of Russian uranium since the early 1990s, when it entered into a suspension agreement with Russia as part of uranium antidumping proceedings.

 

2014 ANNUAL INFORMATION FORM    Page 10

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

Uranium from US inventories

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

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

The DOE updated its Excess Uranium Inventory Management Plan in 2012 and again in 2013. Overall, total UF₆ volumes and future sales referenced in the plan are generally in line with industry expectations, albeit above the well-known guideline which had limited DOE uranium excess inventory sales to 10% of US reactor fuel requirements. DOE sales will continue to be governed by Secretarial Determinations, which require that any such sales not have a material adverse impact on the US uranium, conversion and enrichment industries. DOE has indicated there will be another Secretarial Determination in 2015. In conjunction with this process, DOE has invited comments from uranium industry players regarding the impact of current and future DOE sales.

Conversion services

We control about 20% of world UF₆ conversion capacity and are a supplier of UO₂ for Canadian-made CANDU reactors.

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 a supplier of UO₂ to CANDU reactors operated in Canada.

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

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

In February 2012, the governments of Canada and China announced an agreement on the terms of a protocol that would facilitate the export of Canadian uranium to China. These arrangements were subsequently ratified by the two governments in 2012 and Canadian uranium can be exported to China.

In November 2013, the government of Canada signed a nuclear co-operation agreement with Kazakhstan. The nuclear co-operation agreement and related administration agreements were ratified and came into force in August 2014. For us, the nuclear co-operation agreement opens opportunities to advance our partnership with Kazakhstan which will strengthen our business and support continued growth.

Our sales commitments

In 2014, 42% of our U₃O₈ sales were to five customers.

We currently have commitments to supply about 200 million pounds of U₃O₈ under long-term contracts with 43 customers worldwide. Our five largest customers account for 50% of these commitments, and 36% of our committed sales volume is

 

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attributed to purchasers in the Americas (US, Canada and Latin America), 41% in Asia and 23% in Europe. We are heavily committed under long-term uranium contracts through 2018, so we are being selective when considering new commitments.

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

Our purchase commitments

In addition, we are active in the spot market buying and selling uranium where it is beneficial for us. Our NUKEM business segment enhances our ability to participate, as they are one of the world’s leading traders of uranium and uranium-related products. We undertake activity in the spot market prudently, looking at the spot price and other business factors to decide whether it is appropriate to purchase or sell into the spot market. We have also bought uranium under long-term contracts, and may do so again in the future. At December 31, 2014, we had firm commitments to buy about 35 million pounds of uranium equivalent from 2015 to 2028.

Our marketing strategy

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

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

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

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

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

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

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

Volumes and pricing

The Ux Consulting estimate for global spot market sales in 2014 was about 42 million pounds, slightly lower than previous years. The Ux Consulting estimate for global long-term contracting in 2014 was about 82 million pounds of U₃O₈, compared to 24 million pounds of U₃O₈ in 2013. Neither buyers nor suppliers are under significant pressure to contract, and suppliers are likely hesitant to lock in meaningful volumes at current price levels.

The industry average spot price (TradeTech and Ux Consulting) on December 31, 2014 was $35.50 (US) per pound U₃O₈, or 3% higher than the December 31, 2013 average of $34.50 (US).

The industry average long-term price (TradeTech and Ux Consulting) was $49.50 (US) per pound U₃O₈ on December 31, 2014, or 1% lower than the December 31, 2013 average of $50.00 (US).

Fuel services

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

 

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

We have a similar marketing strategy for UF₆ conversion services. We sell our conversion services to utilities in the Americas, Europe and Asia and primarily through long-term contracts. We currently have UF₆ conversion services commitments of approximately 70 million kilograms of UF₆ conversion services under long-term contracts with 36 customers worldwide. Our five largest customers account for 56% of these commitments, and of our committed UF₆ conversion services volume, 39% is attributed to purchasers in the Americas, 24% in Asia and 37% in Europe.

In 2015, we plan to produce 9 million to 10 million kgU.

NUKEM

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

NUKEM’s main customers are commercial nuclear power plants using enriched uranium fuel, typically large utilities that are either government-owned or large-scale utilities with multi-billion market capitalization and strong credit ratings. NUKEM also trades with converters, enrichers, other traders and investors. NUKEM has uranium and uranium-related products under contract until 2022.

 

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Operations and projects

Uranium

 

Operating properties
McArthur River/Key Lake			15
Cigar Lake			29
Inkai			43
Rabbit Lake			55
Smith Ranch-Highland			57
Crow Butte			58
Projects under evaluation
Inkai blocks 1 and 2 production increase (see Inkai, above)			43
Inkai block 3 (see Inkai, above)			43
Millennium			59
Yeelirrie			60
Kintyre			61
Exploration			62

Fuel services

 

Refining
Blind River refinery			63
Conversion and fuel manufacturing
Port Hope conversion services			64
Cameco Fuel Manufacturing Inc.			64

NUKEM

 

NUKEM GmbH			66

Uranium production

 

Cameco’s share (million lbs U3O8)		2012				2013				2014
McArthur River/Key Lake			13.6				14.1				13.3
Cigar Lake			—				—				0.2
Rabbit Lake			3.8				4.1				4.2
Smith Ranch-Highland			1.1				1.7				2.1
Crow Butte			0.8				0.7				0.6
Inkai			2.6				3.0				2.9
Total			21.9				23.6				23.3

 

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Uranium – operating properties

 

		McArthur River/Key Lake   McArthur River is the world’s largest high-grade uranium mine, and Key Lake is the largest uranium mill in the world.   Ore grades at the McArthur River mine are 100 times the world average, which means it can produce more than 18 million pounds per year by mining only 150 to 200 tonnes of ore per day. We are the operator.   McArthur River is one of our three material uranium properties.
Location		Saskatchewan, Canada
Ownership		69.805% - McArthur River 83.33% - Key Lake
End product		uranium concentrates
ISO certification		ISO 14001 certified
Mine type		underground
Estimated mineral reserves (our share)		241.0 million pounds (proven and probable) average grade U3O8 – 14.87%
Estimated mineral resources (our share)		7.4 million pounds (measured and indicated) average grade U3O8 – 4.24% 39.9 million pounds (inferred) average grade U3O8 – 7.38%
Mining methods		primary: raiseboring secondary: blasthole stoping and boxhole boring
Licensed capacity		mine: 21 million pounds per year mill: 25 million pounds per year
Total production    2000 to 2014 (100% basis)          1983 to 2002		269.7 million pounds (McArthur River/Key Lake) 209.8 million pounds (Key Lake)
2014 production (our share)		13.3 million pounds
2015 forecast production (our share)		13.7 million pounds
Estimated mine life		2033 (based on current mineral reserves)
Estimated decommissioning cost (100% basis)		$48 million - McArthur River $218 million - Key Lake

Business structure

 

 

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History

 

1976		•		Canadian Kelvin Resources Ltd. and Asamera Oil Corporation Ltd. form an exploration joint venture, which includes the lands that the McArthur River mine is situated on
1977		•		Saskatchewan Mining Development Corporation (SMDC), one of our predecessor companies, acquires a 50% interest
1980		•		McArthur River joint venture is formed
		•		SMDC becomes the operator
		•		Active surface exploration begins
		•		Between 1980 and 1988 SMDC reduces its interest to 43.991%
1988		•		Eldorado Resources Limited merges with SMDC to form Cameco
		•		We become the operator
		•		Deposit discovered by surface drilling
1988-1992		•		Surface drilling reveals significant mineralization of potentially economic uranium grades, in a 1,700 metre zone at between 500 to 640 metres
1992		•		We increase our interest to 53.991%
1993		•		Underground exploration program receives government approval – program consists of shaft sinking (completed in 1994) and underground development and drilling
1995		•		We increase our interest to 55.844%
1997-1998		•		Federal authorities issue construction licences for McArthur River after reviewing the environmental impact statement, holding public hearings, and receiving approvals from the governments of Canada and Saskatchewan
1998		•		We acquire all of the shares of Uranerz Exploration and Mining Ltd. (UEM), increasing our interest to 83.766%
		•		We sell half of the shares of UEM to AREVA, reducing our interest to 69.805%, and increasing AREVA’s to 30.195%
1999		•		Federal authorities issue the operating licence and provincial authorities give operating approval, and mining begins in December
2003		•		Production is temporarily suspended in April because of a water inflow
		•		Mining resumes in July
2009		•		UEM distributes equally to its shareholders:
				•     its 27.922% interest in the McArthur River joint venture, giving us a 69.805% direct interest, and AREVA a 30.195% direct interest
				•     its 33 1⁄3% interest in the Key Lake joint venture, giving us an 83 1⁄3% direct interest, and AREVA a 16 2⁄3% direct interest
2013		•		Federal authorities granted a 10-year renewal of the McArthur River and Key Lake operating licences
2014		•		After a two-week labour disruption, we enter into a four-year collective agreement with unionized employees at McArthur River and Key Lake operations

 

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Technical report

 

 

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

About the McArthur River property

Location

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

Accessibility

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

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

Leases

Surface lease

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

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

Mineral lease

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

Mineral claims

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

Climate

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

 

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Setting

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

Geology

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

Mineralization

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

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

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

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

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

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

 

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Orthogonal View of Underground Development and Mineralized Zones Looking Northwest

About the McArthur River mine

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

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

McArthur River currently has six areas with delineated mineral reserves and delineated mineral resources (Zones 1 to 4, Zone 4 South and Zone B) and two additional areas with delineated mineral resources (Zone A and McArthur North). We are currently mining Zone 2 and Zone 4.

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

Zone 4 is divided into three mining areas: central, north and south. We are actively mining the central area and began mining in Zone 4 North in the fourth quarter of 2014.

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

 

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Permits

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

 

•

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

 

•

Approval to Operate Pollutant Control Facilities – renewed in 2014 and expires on October 31, 2016 (from the Saskatchewan Ministry of Environment)

 

•

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

Infrastructure

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

 

 

To support changes that optimize the production schedule, we plan to expand mine infrastructure (see McArthur River production expansion on pages 22 and 23 for more information).

Water, power and heat

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

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

Employees

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

Mining method

We use a number of innovative methods and techniques to mine the McArthur River deposit.

Ground freezing

The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. We use ground freezing to form an impermeable wall around the area being mined. This prevents the water in the sandstone from entering the mine, and helps stabilize weak rock formations. Ground freezing reduces, but does not eliminate, the risk of water inflows. To date, we have isolated six mining areas with freeze walls.

Raisebore mining

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

 

•

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

 

•

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

 

•

once mining is complete, filling each raisebore hole with concrete

 

•

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

 

•

starting the process again with the next raisebore chamber.

 

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In 2013, the CNSC granted approval for the use of two secondary extraction methods: blasthole stoping and boxhole boring.

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

Boxhole boring

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

Test mining to date has identified this as a viable mining option; however, only a minor amount of ore is scheduled to be extracted using this method.

Blasthole stoping

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

Blasthole stoping is planned in areas where blast holes can be accurately drilled and small stable stopes excavated without jeopardizing the freeze wall integrity. We expect this method to allow for more economic recovery of ore on the periphery of the orebody, as well as smaller, lower grade areas, and we continue to study opportunities to increase the use of blasthole stoping, which would improve cost efficiency and productivity.

Initial processing

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

 

•

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

 

•

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

 

•

it is blended and thickened, removing excess water

 

•

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

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

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 and low grade ore (>0.03% U3O8) – stored on engineered lined pads

 

•

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

Water inflows

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

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

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

 

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Pumping capacity and treatment limits

Our standard for this project is to secure pumping capacity of at least one and a half times the estimated maximum sustained inflow. We review our dewatering system and requirements at least once a year and before we begin work on any new zone. We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum sustained inflow. As our mine plan is advanced, we plan to make improvements in our dewatering system and to expand our water treatment capacity.

Production

 

•

2014: 19.1 million pounds of U3O8 was produced by milling McArthur River ore at Key Lake (our share was 13.3 million pounds). Average mill metallurgical recovery was 99.4%.

 

•

Forecast: 19.6 million pounds of U3O8 (our share 13.7 million pounds) (which includes processing downblended material at Key Lake) until we receive the required regulatory approvals and complete the work necessary to increase production at both McArthur River and Key Lake (see McArthur River production expansion below). The total life-of-mine mill production forecast as of December 31, 2014 is estimated to be 341.3 million pounds of U3O8 (our share 239.5 million pounds), based on an overall milling recovery of 99.4% (which does not include processing downblended material at Key Lake).

Payback

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

Recent activity

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

In 2012, we completed the feasibility study on the McArthur River extension project and based on the positive results, we revised our mine plan to incorporate a mine expansion.

McArthur River production expansion

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

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

 

•

obtain all the necessary regulatory approvals

 

•

expand the freeze plant and electrical distribution systems

 

•

optimize our mine ventilation system

 

•

improve our dewatering system and expand our water treatment capacity, as required to mitigate capacity losses should mine developments increase background water volumes

 

•

expand the concrete distribution systems and batch plant capacity.

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

As we advance our production plan, our ventilation demands will also increase. We have developed a staged strategy for improving ventilation at the mine prior to committing to a fourth ventilation raise to surface.

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

 

•

Expansion of the existing freeze plant: Expansion of the existing freeze plant from 800 tonnes to 1,300 tonnes was completed and commissioned in 2014.

 

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•

South freeze plant: A modular freeze plant with initial capacity of 500 to 750 tonnes of freeze capacity is planned for the south mining areas and is scheduled to be completed by 2017.

 

•

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

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

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

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

Key Lake mill

Location

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

Permits

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

 

•

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

 

•

Approval to Operate Pollutant Control Facilities – renewed in 2014 and expires on November 30, 2021 (from the Saskatchewan Ministry of Environment).

In 2014, the CNSC approved the environmental assessment (EA) for the Key Lake extension project, a project which involves increasing our tailings capacity and Key Lake’s nominal annual production rate. The licence conditions handbook now allows the Key Lake mill to produce up to 25.0 million pounds (100% basis) per year.

With the approved EA and once the Key Lake extension project is complete, mill production can be increased to closely follow production from the McArthur River mine. There will be differences in a given production year between mine and mill production due to the addition of mineralized material stockpiled at Key Lake, processing downblended material (see page 84), year to year inventory changes and recovery rate.

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 16 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.

 

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•

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

The agreement was amended again in 2011 and now requires:

 

•

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

 

•

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

Process

The Key Lake mill uses a seven-step process:

 

•

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

 

•

dissolve the uranium using a leaching circuit

 

•

clarify the uranium in solution using a counter current decantation circuit

 

•

concentrate it using a solvent extraction circuit

 

•

precipitate it with ammonia

 

•

thicken, dewater and dry it

 

•

package it as 98% U3O8 (yellowcake).

Waste rock

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

 

•

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

 

•

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

Treatment of effluent

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

Tailings capacity

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

 

•

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

 

•

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

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

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

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

In 2014, the CNSC approved an increase in Key Lake’s tailings capacity. We now expect to have sufficient tailings capacity to mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

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 closely follow annual production rates from the McArthur River mine. The plan includes upgrading circuits with new technology to simplify operations and improve environmental performance. We have been refurbishing or

 

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replacing selected areas of the existing infrastructure since 2006. Our new acid, oxygen and steam plants are operational. We received approval from the CNSC to increase tailings capacity – see Tailings capacity, above.

The current focus is on the product-end of the mill, including solvent extraction (SX), ammonium sulphate crystallization and calcining circuits. A project to replace the existing substation was completed in 2013. This new infrastructure has sufficient capacity to meet future electrical demands. Construction of the new calciner circuit continued in 2014. This new equipment will also have sufficient capacity to meet long term requirements and commissioning is expected to be completed in 2015.

Decommissioning and financial assurances

In 2003, we prepared a preliminary decommissioning plan for both McArthur River and Key Lake, which were approved by the CNSC and the Saskatchewan Ministry of the Environment. In 2008, when we renewed our CNSC licence, we revised the accompanying preliminary decommissioning cost estimates. In 2013, when we again renewed our CNSC licence, we revised the accompanying preliminary decommissioning cost estimates. Our Key Lake preliminary decommissioning cost estimate was further revised and submitted to the CNSC in 2014 and we received final approval from the CNSC in January 2015. These documents include our estimated cost for implementing the decommissioning plan and addressing known environmental liabilities.

We, along with our joint venture partner, have letters of credit posted as financial assurances with the government of Saskatchewan to cover the amount in the 2013 preliminary decommissioning cost estimate for McArthur River ($48 million) and are in the process of updating the letters of credit for the preliminary decommissioning cost estimate that was approved in 2015 for Key Lake ($218 million).

Exploration, drilling and estimates

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

In total, exploration drilling of the McArthur River deposit to date consists of over 1,345 drillholes and 268,000 metres. Drilling has been carried out from both surface and underground in order to locate and delineate mineralization. Surface exploration drilling is initially used in areas where underground access is not available and is used to guide the underground exploration programs. The deposit consists of nine distinct mineralized areas and three under-explored surface defined mineralized showings over a potential strike length of 2,700 metres. Five of these have been well defined with underground drilling, namely Zones 1 to 4 and Zone 4 South. The remaining seven, McA North (1-4), McA South (1), Zone A and Zone B are based entirely on surface drilling. McA North (1) has recently experienced underground drilling (results pending). Underground drilling is planned to start on Zone B and McA North (2) in 2015. Three under-explored mineralized showings, as well as other mineralized occurrences, will be pursued if warranted.

Surface drilling

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

As of December 31, 2014, we had drilled 257 surface drillholes (both conventional and directional drilling) for a total of approximately 170,500 metres along the P2 trend.

We have completed preliminary drill tests of the P2 trend at 200 metre intervals over 11.5 kilometres (4.3 kilometres northeast and 6.4 kilometres southwest of the McArthur River deposit) of the total 13.75 kilometres strike length of the P2 trend. Surface exploration drilling in 2014 tested the North 3 and North 5 target area as well as reconnaissance testing of the hanging wall of the P2 fault. A total of $1.2 million (our share $838,000) has been budgeted in 2015 for surface diamond drilling to evaluate potential extensions of the P2 fault southwest of the mine.

Underground drilling

 

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

We have drilled more than 1,088 underground drillholes since 1993, over 97,780 metres, to get detailed information along 1,400 metres of the surface delineation, and used this data to estimate the mineral reserves and resources in five mineralized zones (Zones 1 to 4 and Zone 4 South). The drilling was primarily completed from the 530 and 640 metre levels. Data from hundreds of freezeholes and raisebore pilot holes support the estimate. Where there were no underground drillholes (Zones A, B, McA North (1) and McA North (2) in the northeastern part of the deposit), we used surface exploration drillholes to estimate mineral resources.

In addition to the exploration drilling, geological data is also collected from the underground probe and grout, service, drain, freezeholes and geotechnical programs.

Recent activity

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

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

In 2015, we plan to continue advancing the underground exploration drifts to the southwest and northeast directions. Additional drilling is planned underground to delineate Zone A and Zone B, and from surface to identify additional mineral resources in the deposit.

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, where possible.

 

•

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.

 

•

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

 

•

Core recovery in these areas can be excellent to poor.

 

•

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

 

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Analysis

We record the following for each sample:

 

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.

Sample security

Samples include chain of custody documentation that accompanies the samples during transportation to the laboratory for analysis.

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.

 

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Accuracy

We are satisfied with the quality of data obtained from surface exploration and underground drilling at McArthur River and consider it valid for estimating mineral resources and mineral reserves. This is supported by the fact that for the last five years, our estimation of tonnage, grade and pounds showed differences of 9%, -7% and 2% respectively compared to production.

Mineral reserve and resource estimates

Please see page 67 for our mineral reserve and resource estimates for McArthur River.

 

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Uranium – operating properties
		Cigar Lake   Cigar Lake is the world’s second largest high-grade uranium deposit, with grades that are 100 times the world average. We are a 50% owner and the mine operator. Cigar Lake uranium will be milled at AREVA’s McClean Lake JEB mill.   Cigar Lake 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)		117.5 million pounds (proven and probable) average grade U3O8 – 17.84%
Estimated mineral resources (our share)		2.3 million pounds (measured and indicated), average grade U3O8 – 8.84% 52.5 million pounds (inferred), average grade U3O8 – 16.22%
Mining method		jet boring
Licensed capacity		mine: 18 million pounds per year mill: currently 11 million pounds per year; an application is expected to be submitted in 2015 to increase licensed capacity to 24 million pounds per year
Total production (our share)		0.2 million pounds
2014 production (our share)		0.2 million pounds
2015 forecast production (our share)		3.0 to 4.0 million pounds
Estimated mine life		2028 (based on current mineral reserves)
Estimated decommissioning cost (100% basis)		$49 million

Business structure

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

 

•

Cameco – 50.025% (operator)

 

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AREVA – 37.1%

 

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Idemitsu Canada Resources Ltd. – 7.875%

 

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TEPCO Resources Inc. – 5.0%

 

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History

 

1976		•		Canadian Kelvin Resources and Asamera Oil Corporation form an exploration joint venture, which includes the lands that the Cigar Lake mine is being built on
1977		•		Saskatchewan Mining Development Corporation (SMDC), one of our predecessor companies, acquires a 50% interest
1980		•		Waterbury Lake joint venture formed, includes lands now called Cigar Lake
1981		•		Deposit discovered by surface drilling – it was delineated by a surface drilling program between 1982 and 1986
1985		•		Reorganization of the Waterbury Lake joint venture - Cigar Lake Mining Corporation becomes the operator of the Cigar Lake lands and a predecessor to AREVA becomes the operator of the remaining Waterbury Lands
		•		SMDC has a 50.75% interest
1987-1992		•		Test mining, including sinking shaft 1 to 500 metres and lateral development on 420 metre, 465 metre and 480 metre levels
1988		•		Eldorado Resources Limited merges with SMDC to form Cameco
1993-1997		•		Canadian and Saskatchewan governments authorize the project to proceed to regulatory licensing stage, based on recommendation of the joint federal-provincial panel after public hearings on the project’s environmental impact
2000		•		Jet boring mining system tested in waste and frozen ore
2001		•		Joint venture approves a feasibility study and detailed engineering begins in June
2002		•		Joint venture is reorganized, new joint venture agreement is signed, Rabbit Lake and JEB toll milling agreements are signed, and we replace Cigar Lake Mining Corporation as Cigar Lake mine operator
2004		•		Environmental assessment process is complete
		•		CNSC issues a construction licence
2005		•		Development begins in January
2006		•		Two water inflow incidents delay development:
				•    in April, shaft 2 floods
				•    in October, underground development areas flood
		•		In November, we begin work to remediate the underground development areas
2008		•		Remediation interrupted by another inflow in August, preventing the mine from being dewatered
2009		•		Remediation of shaft 2 completed in May
		•		We seal the 2008 inflow in October
2010		•		We finish dewatering the underground development areas in February, establish safe access to the 480 metre level, the main working level of the mine, and backfill the 465 metre level
		•		We substantially complete clean-up, inspection, assessment and securing of underground development and resume underground development in the south end of the mine
2011		•		We begin to freeze the ground around shaft 2 and restart freezing the orebody from underground and from the surface
		•		We resume the sinking of shaft 2 and early in 2012 achieve breakthrough to the 480 metre level, establishing a second means of egress for the mine
		•		We receive regulatory approval of our mine plan and begin work on our Seru Bay project
		•		Agreements are signed by the Cigar Lake and McLean Lake joint venture partners to mill all Cigar Lake ore at the McClean Lake JEB mill and the Rabbit Lake toll milling agreement is terminated
2012		•		We achieve breakthrough to the 500 metre level in shaft 2
		•		We assemble the first jet boring system unit underground and move it to a production tunnel where we commence preliminary commissioning
2013		•		CNSC issues an eight-year operating licence
		•		We begin jet boring in ore
2014		•		McClean Lake mill starts producing uranium concentrate from Cigar Lake ore

 

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Technical report

 

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

About the property

Location

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

Accessibility

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

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

Leases

Surface lease

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

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

Mineral lease

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

Mineral claims

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

 

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Climate

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

Setting

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

Geology

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

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

Mineralization

The Cigar Lake deposit is approximately 1,950 metres long, 20 to 100 metres wide, and ranges up to 14.3 metres thick, with an average thickness of about 5.3 metres. It occurs at depths ranging between 410 to 450 metres below the surface.

The deposit has three distinct styles of mineralization:

 

•

high-grade mineralization at the unconformity

 

•

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

 

•

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

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

About the operation

Cigar Lake has sufficient surface rights to meet future mining operation needs for the current mineral reserves.

Permits

Please see page 39 for more information about regulatory approvals for Cigar Lake.

 

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Infrastructure

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

 

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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Orthogonal View of Underground Development and Mineralized Zones Looking Northwest

Bulk freezing

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

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

We are using a hybrid freezing approach with a combination of underground and surface freezing and are continuing to advance our surface freeze program to support future production. Through 2014, we continued to drill freezeholes from surface, expand the surface freezing infrastructure and put the new freezeholes into operation.

Jet boring

After many years of test mining, we selected jet boring, a non-entry mining method, which we have developed and adapted specifically for this deposit. This method involves:

 

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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

 

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•

collecting the ore and water mixture (slurry) from the cavity and pumping it to storage (sump storage), allowing it to settle

 

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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 worker exposure to radiation levels. 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 method in trials and initial mining to date, this method has not been proven at full production and we continue with commissioning work to determine if the method is capable of achieving the designed annual production rate. Mining has been completed on a limited number of cavities that may not be representative of the deposit as a whole. As we ramp up production, there may be some technical challenges, which could affect our production plans including, but not limited to, variable or unanticipated ground conditions, ground movement and cave-ins, water inflows and variable dilution, recovery values and mining productivity. There is a risk that the rampup to full production may take longer than planned and that the full production rate may not be achieved on a sustained and consistent basis. We are confident we will be able to solve challenges that may arise, but failure to do so would have a significant impact on our business.

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

 

•

began preliminary commissioning and system testing

 

•

installed temporary infrastructure to support testing in waste rock.

In 2013, we assembled the second jet boring machine and completed our staged commissioning program for the jet boring machines, including jetting of a waste and an ore cavity. Ore production started in March 2014 and the McClean Lake mill started producing uranium concentrates from the ore in October 2014.

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

All three jet boring machines are currently on site and the third is expected to be in operation underground in 2015.

Mine development

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

Mine development for both construction and operation has used three basic development systems: drill and blast with conventional ground support, NATM (New Austrian Tunneling Method), and MDS (mine development system), a 5.1 metre diameter full face tunnel boring machine, which installs a precast concrete tunnel lining for ground support. No MDS development has been done since 2011. Geotechnical drilling and analysis of ground conditions is completed prior to confirming permanent infrastructure locations.

We continue to observe areas of spalling, cracking and displacement in a number of sections of concrete segmental tunnels that were installed using MDS between 1999 and 2006. One area was refitted with a yielding liner in 2013, and another is currently being refitted. Other areas are continuing to show signs of weakening due to ground movement. We have installed rockbolts, screen and, in some areas ring beams, as temporary measures designed to protect personnel from falling debris and to maintain the integrity of the tunnels. Monitoring of these tunnels is ongoing and long-term solutions are being engineered. We have experienced ground movement in localized areas of one tunnel which led to a minor delay in production

 

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while the affected area was rehabilitated. While we believe that the rehabilitation should safely stabilize the tunnels, any further rehabilitation nonetheless may cause delays in mining.

We plan for our mine development to take place away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk, and apply extensive additional technical and operating controls for all higher risk development. See Rehabilitating the mine below.

Processing

Cigar Lake ore slurry will be processed in two steps:

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

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

Tailings

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

Waste

The waste rock piles are separated into three categories:

 

•

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

 

•

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

 

•

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

Water discharged from the mine has historically been treated and released to Aline Creek. We began discharging treated water to Seru Bay in August 2013 following receipt of approval from the CNSC and the province of Saskatchewan.

Production

We began production in 2014. The mining plan is designed to extract all of the current mineral reserves. The following is a general summary of the production schedule guideline and parameters on a 100% basis:

 

Total mill production		•		231.3 million pounds of U3O8, based on an overall milling recovery of 98.5%
		•		Full annual production of 18 million pounds of U3O8
Total mine production		•		597 thousand tonnes of ore
Average annual mine production		•		100 to 165 tonnes per day during peak production, depending on ore grade
Average mill feed grade		•		17.8% U3O8

We expect to begin commercial production in 2015. We expect Cigar Lake to produce between 6 and 8 million packaged pounds in 2015; our share is 3 million to 4 million pounds.

Payback

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

Costs (all showing our share)

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

 

•

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

 

•

expensed about $91 million in remediation expenses

 

•

expensed about $111 million in standby costs

 

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

 

•

$83 million on the McClean Lake mill

 

•

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

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

In addition, during the year, we spent:

 

•

$57 million on operating costs

 

•

$21 million to complete various capital projects at site

 

•

$39 million on underground development

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

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

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

Assumptions

 

•

our Cigar Lake development, mining and production plans succeed

 

•

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

 

•

there are no labour disputes or shortages

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

Material risks

 

•

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

 

•

ground movements and cave-ins

 

•

we cannot obtain or maintain the necessary regulatory permits or approvals

 

•

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

 

•

sufficient tailings facility capacity is not available

 

•

our mineral reserves estimate is not reliable

 

•

our development, mining or production plans for Cigar Lake are delayed or do not succeed for any reason, including technical difficulties with the jet boring mining method or freezing the deposit to meet production targets, the third jet boring machine does not commence operating on schedule in 2015 or operate as expected, technical difficulties with the McClean Lake JEB mill modifications or expansion or milling Cigar Lake ore.

 

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Reclamation and financial assurances

In 2002, our preliminary decommissioning plan for Cigar Lake was approved by the CNSC and the Saskatchewan Ministry of Environment. We revised this plan and the accompanying preliminary decommissioning cost estimate when we renewed our federal licence in 2008. We revised this plan and the accompanying preliminary decommissioning cost estimate again when we received our operating licence in 2013.

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

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

Water inflow and mine rehabilitation

Cigar Lake Water inflow incidents

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

We developed and successfully executed recovery and remediation plans for both the shaft 2 inflow and the two 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 remediated 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 was completed in 2011.

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

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

Construction

With the mine fully secured, the underground rehabilitation program complete and regulatory requirements met, we resumed underground construction activities in 2011.

Completing shaft 2

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

Increase pumping capacity

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

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

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

 

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Surface construction

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

Underground development

The construction of the underground processing facility was completed in 2014 including: the JBS mining infrastructure (pumps, filters, etc.), Run of Mine (ROM) storage facility, crushing and grinding circuits, clarifier system, and ore slurry hoisting. The construction of the ancillary systems is also complete including wash facilities, shops, compressed air, electrical supply, fresh water, and recycled water systems. Commissioning of the processing facility and systems is substantially complete. In 2014, we also advanced underground development for future production tunnels. We will continue advancing underground development for future production tunnels in 2015.

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. We ceased incurring standby costs as of August 31, 2014.

The McClean Lake mill started receiving Cigar Lake ore in March 2014 and produced its first drum of Cigar Lake yellowcake in October 2014. All of Cigar Lake’s ore slurry from current mineral reserves will be processed at the McClean Lake mill, operated by AREVA. The McClean Lake mill requires modification and expansion to process and package all of the Cigar Lake’s current mineral reserves. In 2014, the McClean Lake mill completed the first stage of mill upgrades. These initial modifications primarily focused on upgrades to the existing leach circuit and associated hydrogen mitigation systems to allow them to process high-grade ore.

In order to meet Cigar Lake’s rampup schedule, the McClean Lake mill must be expanded. These upgrades include: a second solvent extraction circuit to accommodate increased flows; a new tailings neutralization circuit; an additional CX plant to handle the increased ammonium sulphate flow; modifications to the existing acid plant; and new diesel generators. Construction of the expanded facility is scheduled to be completed in 2015.

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

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

Regulatory approvals

Operating licence

 

•

The CNSC issued an eight-year operating licence in June 2013 for the Cigar Lake mine.

Processing licences

 

•

In 2012, the CNSC approved an amendment to the operating licence for the McClean Lake JEB mill to process Cigar Lake ore.

 

•

In 2015, it is expected that an application will be submitted to increase licensed capacity at the McClean Lake JEB mill to 24 million pounds per year.

 

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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 began discharging treated water to Seru Bay in August 2013 following the receipt of approvals from the CNSC and the province of Saskatchewan.

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 899 surface holes have been drilled totaling 409,338 metres. 714 of these were drilled within the known deposit limits.

 

1982 – 1986		A major surface drilling program delineated the deposit
1987 – 2002		Drilling for geotechnical and infill holes
2007 – 2009		51 holes drilled for various geotechnical and geophysical programs
2010		45 drillholes were completed as part of delineation and geotechnical programs
2011		87 drillholes were completed as part of delineation, geotechnical and surface freezehole programs
2012		188 drillholes were completed as part of surface delineation, freezehole and hydrogeological monitoring programs
2013		154 drillholes were completed as part of the surface freezehole drilling program
2014		150 drillholes were completed as part of the surface freezehole drilling program and one exploration drillhole was completed east of the main deposit area.

In 2015, we plan to continue the surface freezehole drilling program.

Surface drilling – mineral claims

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

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

Underground drilling

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

 

1989 – 2006		132 underground diamond drillholes were drilled totaling 11,108 metres. Of these, 10 intersected the deposit.   A total of 347 freeze and temperature monitoring holes were drilled from the underground workings during the construction phase. 182 of these were gamma surveyed by radiometric probing.   Due to the drilling method for freezeholes, no core is available for assays. Uranium content is estimated by radiometric probing of the holes. In 2011, we developed conversion coefficients to convert the radiometric probe results to equivalent U3O8 grades. This allowed the 182 underground freezeholes to be incorporated into the Cigar Lake mineral resource model.
2007 – 2009		There was no underground drilling because of flooding.

 

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2010 – 2014		300 holes were drilled underground totaling 24,779 metres.   5 of the 300 holes were drilled from inside shaft 2, in advance of the top seal grout cover.   255 holes were drilled from the 480 metre level and the remaining 40 holes were drilled from the 500 metre level.

In 2015, we plan to continue drilling from the 480 and 500 metre levels 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.

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

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

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

Phase 1 – the eastern part (700 metres long by 110 metres wide)

 

•

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

 

•

the central area of Phase 1 has been further defined by 539 surface freezeholes and surface temperature monitoring holes drilled at nominal 5 metre spacing. A total of 81 of these freezeholes and temperature monitoring holes have been assayed sampled through the mineralized zone. A total of 508 have been gamma probed to determine the equivalent uranium grades to be used for mineral resource estimation.

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

 

•

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

 

•

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

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

Analysis

 

•

More than 9,500 samples were collected from surface and underground drilling.

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

Width		Assay		Density
•       largest 14.3 metres   •       smallest 0.5 metres   •       average 5.3 metres		•       highest 82.86% U3O8   •       lowest 0.00% U3O8		•       highest 6.46 g/cm3   •       lowest 1.17 g/cm3

 

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Quality control and data verification

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

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

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

 

•

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

 

•

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

 

•

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

 

•

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

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

Sample security

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

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

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

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

Mineral reserve and resource estimates

Please see page 67 for our mineral reserve and resource estimates for Cigar Lake.

 

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Uranium – operating properties

 

		Inkai   Inkai is a very significant uranium deposit, located in Kazakhstan. There are two production areas (blocks 1 and 2) and an exploration area (block 3). The operator is Joint Venture Inkai Limited Liability Partnership, which we jointly own (60%) with Kazatomprom (40%).   Inkai is one of our three material uranium properties.
Location		South Kazakhstan
Ownership		60%
End product		uranium concentrates
Certifications		BSI OHSAS 18001 ISO 14001 certified
Estimated mineral reserves		45.6 million pounds (proven and probable)
(our share)(1)		average grade U3O8 – 0.07%
Estimated mineral resources (our share)(2)		30.0 million pounds (indicated) average grade U3O8 – 0.08%   145.9 million pounds (inferred) average grade U3O8 – 0.05%
Mining method		in situ recovery (ISR)
Licensed capacity		5.2 million pounds per year (our share 3.0 million pounds per year)
Total production 2008 to 2014 (our share)		14.9 million pounds
2014 production (our share)		2.9 million pounds
2015 forecast production (100% basis)		5.2 million pounds (our share 3.0 million pounds)
Estimated mine life		2030 (based on current licence term)
Estimated decommissioning cost (100% basis)		$9 million (US)

 

(1)	Our share of uranium in the mineral reserves is based on our interest in planned production (57.5%) assuming an annual production rate of 5.2 million pounds, which differs from our ownership interest (60%).

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

 

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Business structure

Inkai is a Kazakhstan limited liability partnership between two companies:

 

•

Cameco – 60%

 

•

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

History

 

1976-78		•		Deposit is discovered
		•		Exploration drilling continues until 1996
1979		•		Regional and local hydrogeology studies begin
		•		Borehole tests characterize the four aquifers within the Inkai deposit (Uvanas, Zhalpak, Inkuduk and Mynkuduk)
1988		•		Pilot test in the northeast area of block 1 begins, lasts 495 days and recovers 92,900 pounds of uranium
1993		•		First Kazakhstan estimates of uranium reserves for block 1
1996		•		First Kazakhstan estimates of uranium reserves for block 2
		•		Kazakhstan regulators registers Inkai, a joint venture among us, Uranerzbergbau-GmbH and KATEP
1997-1998		•		Kazatomprom is established
		•		KATEP transfers all of its interest in the Inkai joint venture to Kazatomprom
1998		•		We acquire all of Uranerzbergbau-GmbH’s interest in the Inkai joint venture, increasing our interest to 66 2/3%
		•		We agree to transfer a 6 2/3% interest to Kazatomprom, reducing our holdings to a 60% interest
1999		•		Inkai receives a mining licence for block 1 and an exploration licence for blocks 2 and 3 from the government of Kazakhstan
2000		•		Inkai and the government of Kazakhstan sign a subsoil use contract (called the resource use contract), which covers the licences issued in 1999 (see above)
2002		•		Test mining operations at block 2 begins
2005		•		Construction of ISR commercial processing facility at block 1 begins
2006		•		Complete test mine expansion at block 2
2007		•		Sign Amendment No.1 to the resource use contract, extending the exploration period at blocks 2 and 3
2008		•		Commission front half of the main processing plant in the fourth quarter, and begin processing solution from block 1
2009		•		Sign Amendment No. 2 to the resource use contract, which approves the mining licence at block 2, extends the exploration licence for block 3 to July 13, 2010, and requires Inkai to adopt the new tax code and meet the Kazakhstan content thresholds for human resources, goods, works and services
		•		Commission the main processing plant, and started commissioning the first satellite plant
2010		•		Receive regulatory approval for commissioning of the main processing plant
		•		File a notice of potential commercial discovery at block 3
		•		Receive approval in principle for the extension of the block 3 exploration licence for a five-year appraisal period that expires July 2015, and an increase in annual production from blocks 1 and 2 to 3.9 million pounds (100% basis)
2011		•		Receive regulatory approval for commissioning of the first satellite plant
		•		Sign Amendment No. 3 to the resource use contract, which extends the exploration licence for block 3 to July 2015 and provides government approval to increase annual production from blocks 1 and 2 to 3.9 million pounds (100% basis)
		•		Sign a memorandum of agreement with Kazatomprom to increase annual production from blocks 1 and 2 from 3.9 million pounds to 5.2 million pounds (100% basis)
2012		•		Sign a memorandum of agreement with Kazatomprom setting the framework to increase annual production from blocks 1 and 2 to 10.4 million pounds (100% basis), to extend the term of Inkai’s resource use contract through 2045 and to cooperate on the development of uranium conversion capacity, with the primary focus on uranium refining rather than uranium conversion. For more information on this agreement see page 48.
2013		•		Sign Amendment No. 4 to the resource use contract, which provides government approval to increase annual production from blocks 1 and 2 to 5.2 million pounds (100% basis)

 

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Technical report

 

 

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

About the Inkai property

Location

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

Accessibility

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

Licences

Inkai holds the rights to three contiguous licence blocks, blocks 1, 2 and 3, based on the licences it has received and its resource use contract with the Kazakhstan government. Inkai has to meet certain obligations to maintain these rights. See page 49 for more information.

Setting

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

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

Geology

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

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

 

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

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

Mineralization

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

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

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

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

Block 3 update

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

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

In April 2012, Inkai received regulatory approval for the detailed block 3 delineation and test leach work programs. In 2012, Inkai continued delineation drilling, started technological drilling at test wellfields and started construction of the test leach facility. In 2013, Inkai completed exploration drilling, continued construction of the test leach facility and test wellfields, and started work on an appraisal of mineral potential according to Kazakhstan standards.

In 2014, Inkai continued construction of the test leach facility and test wellfields, and advanced work on a preliminary appraisal of the mineral potential according to Kazakhstan standards. Inkai also paid a $3.2 million (US) commercial discovery bonus to the state in 2014.

The current exploration licence expires in July 2015 and Inkai is working to extend the term. In 2015, Inkai expects to complete construction of the test leach facility and continue working on a final appraisal of the mineral potential according to Kazakhstan standards.

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.

 

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Licences

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

 

•

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

For uranium extraction in block 1 (16.6 square kilometres)

 

•

Licence Series AY 1371D, April 20, 1999

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

Other material licences

 

•

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

 

•

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

 

•

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

 

•

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

These licences are all currently in force and have an indefinite term. Inkai’s material environmental permits are described on page 49.

Infrastructure

 

 

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.

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:

 

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

 

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

 

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precipitate it with hydrogen peroxide

 

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thicken, dewater, and dry it

 

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package it in drums.

 

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The process requires large quantities of sulphuric acid because there are relatively high levels of carbonate in the ore. There were minor weather-related interruptions to Inkai’s sulphuric acid supply during 2014. Given the importance of sulphuric acid to Inkai’s mining operations and shortages in previous years, we closely monitor its availability.

Production

 

Total processing plant production		Based on current mineral reserves, we expect Inkai to produce a total of 67.5 million pounds U3O8 (100% basis, recovered by the processing plant).
Average annual processing plant production		The processing plant has the capacity to produce at an annual rate of 5.2 million pounds per year (100% basis) depending on the grade of the production solution. Inkai has expanded the existing satellite plant capacity in order to support this production rate even at a lower grade. The expansion will be brought online in 2015 following completion of commissioning.

Production increases

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

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

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

Production expansion

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

 

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

 

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

Kazatomprom is pursuing a strategic objective to develop uranium processing capacity in Kazakhstan to complement its leading uranium mining operations. Kazatomprom’s primary focus is now on uranium refining, which is an intermediate step in the uranium conversion process.

We expect to pursue further expansion of production at Inkai at a pace measured to market opportunities. Discussions continue with Kazatomprom.

Sales

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

Funding

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

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

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

Payback

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

 

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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:

 

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

 

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approves mining at block 2

 

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combines blocks 1 and 2 for mining and reporting purposes

 

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

 

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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

 

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

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

 

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

 

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

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

Work programs

Inkai is required to follow the work program appended to the resource use contract, which applies to mining operations over the life of the mine. To comply with the new subsoil law, Inkai developed a life of mine work plan and submitted it to the relevant government authority who approved it in April 2011 as part of the approval of Amendment No. 3 to the resource use contract (see Project documentation on page 51). An updated work program was submitted to the relevant government authority in 2012 in support of the Amendment No. 4 application and was approved in December 2013.

Environment

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

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

Insurance

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

Decommissioning

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

Under the resource use contract, Inkai must submit a plan for decommissioning the mine to the government six months before mining activities are complete. It developed a preliminary decommissioning plan to estimate total decommissioning costs, and updates the plan every five years, or when there is a significant change at the operation that could affect decommissioning estimates. The preliminary decommissioning estimate is $9 million (US).

Groundwater is not actively restored post-mining in Kazakhstan. See page 79 for additional details.

 

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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, as amended December 29, 2014 (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 or law. The state has pre-emptive and approval rights with regards to strategic deposits with some exceptions (for example, for inter-group transfers in certain circumstances), if a subsoil user transfers its subsoil rights or if there is a transfer (direct or indirect) of an ownership interest in a subsoil user.

Subsoil rights go into effect when a contract with the relevant government authority is finalized and registered. 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 pursuant to restrictions and requirements set out by the subsoil law.

On March 12, 2010, the Kazakhstan Ministry of Industry and New Technologies (MINT) replaced the Kazakhstan Ministry of Energy and Mineral Resources (MEMR). MEMR was designated as the “competent authority” under the old law. In August 2014, the Ministry of Energy replaced MINT 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 results of business operations 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 subsoil rights, transfers of shares (interests) in subsoil users and the grant of security over subsoil 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. However, this right is now limited to strategic deposits.

 

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

Under the subsoil law, the relevant government authority can unilaterally terminate a contract before it expires if:

 

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a subsoil user does not fix more than two breaches of its contractual obligations specified in a notification of the relevant government authority within a specific period

 

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subsoil rights or direct and indirect ownership interests in a subsoil user are transferred without consent of the relevant government authority

 

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less than 30% of the financial obligations under a contract are fulfilled during the previous two years

 

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activities of a subsoil user exploring or developing a strategic deposit entails such changes in the economic interests of the state that it poses a threat to national security and the subsoil user does not satisfy the relevant government authority’s request to amend the contract in this regard.

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 or environmental protection 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:

 

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

 

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

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

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

Strategic deposits

According to the Governmental Resolution On Approval of the List of Subsoil (Deposit) Areas having Strategic Importance dated October 4, 2011, 361 various deposits are considered to be strategic deposits, including all three of Inkai’s blocks.

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.

 

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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:

 

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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

 

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

 

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require the sale of foreign currency received by residents

 

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restrict overseas transfers of foreign currency.

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

Exploration, drilling and estimates

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

Exploration

Historical drilling

 

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

 

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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.

 

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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.

 

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

Exploration drilling

 

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

 

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Inkai had drilled a total of 4,295 exploration holes in block 3 as of the end of December 2014 (510 historic holes drilled before 2006, 45 in 2006, 90 in 2008, 456 in 2009, 1,008 in 2010, 494 in 2011, 683 in 2012, 1,009 in 2013, and none were drilled in 2014). 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.

 

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In addition, a total of 79 hydrogeological test wells were drilled between 2010 and 2013. No further holes were drilled in 2014.

Recent activity

 

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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.

 

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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.

 

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

 

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

 

•

Results of exploration and delineation:

 

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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.

 

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encountered more complex morphology of the mineralized zones of block 3

 

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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

 

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

 

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

Sampling and analysis

Sampling

 

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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.

 

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

 

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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.

 

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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.

 

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The split core is tested for grainsize and carbonate content.

 

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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.

 

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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:

 

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

 

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

 

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

Quality control

 

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

 

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

 

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

 

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

 

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Sample security

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

Accuracy

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

Mineral reserve and resource estimates

Please see page 67 for our mineral reserve and resource estimates for Inkai.

 

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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		15.2 million pounds (proven and probable) average grade U3O8 – 0.61%
Estimated mineral resources		22.2 million pounds (indicated) average grade U3O8 – 0.75% 25.9 million pounds (inferred) average grade U3O8 – 0.58%
Mining method		vertical blasthole stoping
Licensed capacity		mill: maximum 16.9 million pounds per year; currently 11 million
Total production 1975 to 2014		198.4 million pounds
2014 production		4.2 million pounds
2015 forecast production		3.9 million pounds
Estimated decommissioning cost		$203 million

Business structure

We own 100% of Rabbit Lake.

Permits

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

 

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Uranium Mine Operating Licence – expires on October 31, 2023 (from the CNSC)

 

•

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

 

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

Production

2014 production was 4.2 million pounds U₃O₈.

 

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Operations

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

Exploration

In 2014, we continued our underground drilling program to delineate resources northeast of the current mine workings and below active mining areas. As a result, we added additional resources at Rabbit Lake. See Mineral reserves and resources on page 67 for more information.

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

Tailings

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

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

Site reclamation

We are proceeding with our multi-year, site wide reclamation plan. We spent over $880,000 in 2014 to reclaim facilities that are no longer in use, and plan to spend $485,000 in 2015.

Mill renewal

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

 

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2006 – reduced mill effluent concentrations of uranium

 

•

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

 

•

2009 – reduced mill effluent concentrations of molybdenum and selenium

 

•

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

 

•

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

 

•

2012 – continued the replacement of mill and site electrical infrastructure

 

•

2013 – rebuilt mill sulfur furnace

 

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2014 – significant repairs to various mill structural steel components and the rebuilding of key mill roof sections.

 

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Uranium – operating properties

 

		Smith Ranch-Highland & Satellite Facilities   We operate Smith Ranch and Highland as a combined operation. Each has its own processing facility, but the Smith Ranch central plant currently processes all the uranium, including uranium from satellite facilities. The Highland plant is currently idle. Together, they form the largest uranium production facility in the United States.
Location		Wyoming, US
Ownership		100%
End product		uranium concentrates
ISO certification		ISO 14001 certified
Estimated mineral reserves		Smith Ranch-Highland: 4.8 million pounds (proven and probable), average grade U3O8 – 0.09% North Butte-Brown Ranch: 2.9 million pounds (proven and probable), average grade U3O8 – 0.08%
Estimated mineral resources		Smith Ranch-Highland: 21.6 million pounds (measured and indicated), average grade U3O8 – 0.06% 7.9 million pounds (inferred), average grade U3O8 – 0.05% North Butte-Brown Ranch: 8.8 million pounds (indicated), average grade U3O8 – 0.07% 0.4 million pounds (inferred), average grade U3O8 – 0.07%
Mining method		in situ recovery (ISR)
Licensed capacity		wellfields: 3 million pounds per year processing plants: 5.5 million pounds per year including Highland mill
Total production 2002 to 2014		19.7 million pounds
2014 production		2.1 million pounds
2015 forecast production		1.4 million pounds
Estimated decommissioning cost		Smith Ranch-Highland $198 million (US); North Butte $22 million (US)

Business structure

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

See our 2014 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		1.7 million pounds (proven) average grade U3O8 – 0.10%
Estimated mineral resources		14.6 million pounds (measured and indicated) average grade U3O8 – 0.27%   2.9 million pounds (inferred) average grade U3O8 – 0.12%
Mining method		in situ recovery (ISR)
Licensed capacity (processing plant and wellfields)		2.0 million pounds per year
Total production 2002 to 2014		9.7 million pounds
2014 production		0.6 million pounds
2015 forecast production		0.3 million pounds
Estimated decommissioning cost		$45 million (US)

Business structure

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

See our 2014 MD&A for more information.

 

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Uranium – projects under evaluation

 

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

Business structure

Millennium is owned by a joint venture of two companies:

 

•

Cameco – 69.9% (operator)

 

•

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

See our 2014 MD&A for more information.

 

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Uranium – projects under evaluation

 

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

Business structure

Yeelirrie is owned 100% by a Cameco subsidiary.

See our 2014 MD&A for more information.

 

2014 ANNUAL INFORMATION FORM    Page 60

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Uranium – projects under evaluation

 

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

Business structure

Kintyre is owned by two companies:

 

•

A Cameco subsidiary – 70%

 

•

Mitsubishi Development Pty Ltd. – 30%

See our 2014 MD&A for more information.

 

2014 ANNUAL INFORMATION FORM    Page 61

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Exploration

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

 

2014 UPDATE

Brownfield exploration

Brownfield exploration is uranium exploration near our existing operations, and includes expenses for advanced exploration projects where uranium mineralization is being defined.

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

Regional exploration

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

PLANS FOR 2015

For 2015, we plan to maintain an active uranium exploration program and continue to focus on our core projects in Saskatchewan under our long-term strategy.

Brownfield exploration

In 2015, we plan to spend approximately $2.8 million on brownfield exploration in Saskatchewan and Australia. Our expenditures on projects under evaluation are expected to total $5.0 million.

Regional exploration

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

 

2014 ANNUAL INFORMATION FORM    Page 62

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Fuel services – refining

 

		Blind River refinery   Blind River is the world’s largest commercial uranium refinery, refining uranium concentrates from mines around the world into UO3.
Location		Ontario, Canada
Ownership		100%
End product		UO3
ISO certification		ISO 14001 certified
Licensed capacity		24 million kgU as UO3 per year (subject to the completion of certain equipment upgrades)
2014 production		8.9 million kgU of UO3
Estimated decommissioning cost		$39 million

Markets

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

Inventory

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

Capacity

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

Licensing

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

 

2014 ANNUAL INFORMATION FORM    Page 63

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Fuel services – conversion and fuel manufacturing

 

		Port Hope conversion services   Port Hope is the only uranium conversion facility in Canada and a supplier of UO2 for Canadian-made CANDU reactors.
Location		Ontario, Canada
Ownership		100%
End product		UF6, UO2
ISO certification		ISO 14001 certified
Licensed capacity		12.5 million kgU as UF6 per year 2.8 million kgU as UO2 per year
Estimated decommissioning cost		$102 million

Cameco Fuel Manufacturing Inc. (CFM)

CFM produces fuel bundles and reactor components for CANDU reactors.

 

Location		Ontario, Canada
Ownership		100%
End product		CANDU fuel bundles and components
ISO certification		ISO 9001 certified, ISO 14001 certified
Licensed capacity		1.2 million kgU as UO2 as finished bundles
Estimated decommissioning cost		$20 million

Port Hope and CFM produced a total of 11.6 million kgU in 2014.

Licensing

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

Conversion services

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

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

 

2014 ANNUAL INFORMATION FORM    Page 64

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

Environment

In 2009, we completed a site-wide environmental investigation of subsurface contamination and a site-wide risk assessment to identify contaminants that could pose a potential risk to the environment. We used the results to develop an environmental management plan to mitigate potential risks. In 2010, we enhanced the plan by adding a number of groundwater retrieval wells. In 2011, we added four additional wells. The environmental management plan met expectations between 2012 and 2014. In 2014, we also met with the regulatory authorities to discuss and agree on the adequacy of the environmental management plan and opportunities to further enhance it through the Vision in Motion project.

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

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

Labour relations

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

Fuel manufacturing

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

Manufacturing services agreements

A substantial portion of CFM’s business is the supply of fuel bundles to the Bruce Power A and B nuclear units in Ontario. We supply the UO₂ for these fuel bundles.

Labour relations

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

 

2014 ANNUAL INFORMATION FORM    Page 65

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NUKEM GmbH

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

 

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

 

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

For more information, see our 2014 MD&A.

 

2014 ANNUAL INFORMATION FORM    Page 66

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Mineral reserves and resources

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

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

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

About mineral resources

Mineral resources that are not mineral reserves have no demonstrated economic viability but do have reasonable prospects for eventual 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 sufficient confidence to allow the appropriate application of technical, economic, marketing, legal, environmental, social and governmental factors to support evaluation of the economic viability of the deposit.

 

•

measured resources: we can confirm both geological and grade continuity to support detailed mine planning.

 

•

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

 

•

Inferred mineral resources are estimated using limited information. We do not have enough confidence to evaluate their economic viability in a meaningful way. You should not assume that all or any part of an inferred mineral resource will be upgraded to an indicated or measured mineral resource, but it is reasonably expected that the majority of inferred mineral resources could be upgraded to indicated mineral resources with continued exploration.

Our share of uranium in the mineral resource tables below is based on our respective ownership interests, except for Inkai which is based on our interest in potential production (57.5%), which differs from our ownership interest (60%).

About mineral reserves

Mineral reserves are the economically mineable part of measured and/or indicated mineral resources demonstrated by at least a preliminary feasibility study. The reference point at which mineral reserves are defined is the point where the ore is delivered to the processing plant. Mineral reserves fall into two categories:

 

•

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

 

•

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

We use current geological models, an average uranium price of $70 (US) per pound U₃O₈ and current or projected operating costs and mine plans to estimate our mineral reserves, allowing for dilution and mining losses. We apply our standard data verification process for every estimate.

Our share of uranium in the mineral reserves table below is based on our respective ownership interests, except for Inkai which is based on our interest in planned production (57.5%) assuming an annual production rate of 5.2 million pounds, which differs from our ownership interest (60%).

Qualified persons

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

 

2014 ANNUAL INFORMATION FORM    Page 67

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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 94 for a discussion of the risks that can affect our business.

Please see pages 73, 74 and 75 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 pre-feasibility studies. Inferred resources have a great amount of uncertainty as to their existence and economic and legal feasibility.

 

2014 ANNUAL INFORMATION FORM    Page 68

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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, 2014 (100% basis – only the second last column shows Cameco’s share)

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

 

				Proven												Probable												Total mineral reserves
Property		Mining method		Tonnes				Grade %U3O8				Content (lbs U3O8)				Tonnes				Grade % U3O8				Content (lbs U3O8)				Tonnes				Grade %U3O8				Content (lbs U3O8)				Cameco’s share of content (lbs U3O8)				Metallurgical recovery (%)
Cigar Lake		underground			205.6				24.00				108.8				391.6				14.60				126.1				597.2				17.84				234.9				117.5			98.5
Key Lake		open pit			67.5				0.50				0.7																67.5				0.50				0.7				0.6			98.7
McArthur River		underground			497.8				18.71				205.3				555.2				11.43				139.9				1,053.0				14.87				345.2				241.0			98.7
Rabbit Lake		underground			32.7				0.26				0.2				1,093.7				0.62				15.0				1,126.4				0.61				15.2				15.2			97
Crow Butte		ISR			801.4				0.10				1.7																801.4				0.10				1.7				1.7			85
Inkai		ISR			1,420.5				0.08				2.6				52,999.2				0.07				76.8				54,419.7				0.07				79.4				45.6			85
North Butte-Brown Ranch		ISR			753.4				0.08				1.4				875.2				0.08				1.5				1,628.6				0.08				2.9				2.9			60
Smith Ranch-Highland		ISR			1,145.5				0.10				2.4				1,241.1				0.09				2.4				2,386.6				0.09				4.8				4.8			80
Total					4,924.4				—				323.1				57,155.9				—				361.6				62,080.3				—				684.6				429.2

Notes

ISR - in situ recovery

Estimates in the above table:

 

•

use an average uranium price of $70 (US) per pound U3O8

 

•

are based on an average exchange rate of $1(US) = $1.05 - $1.10(Cdn)

Totals may not add up due to rounding.

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

METALLURGICAL RECOVERY

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

 

2014 ANNUAL INFORMATION FORM    Page 69

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Changes this year

The table below shows the change in our share of mineral reserves for each property in 2014. The change was mostly the result of:

 

•

production, which removed 24.5 million pounds from our mineral inventory, including first production from Cigar Lake; and

 

•

additional drilling information at Cigar Lake from surface freezeholes.

 

(thousands of pounds U3O8)		December 31, 2013				Throughput(1)				Additions (deletions)(2)				December 31, 2014
Proven mineral reserves
Cigar Lake			57,473				(232	)			(2,810	)			54,431
Crow Butte			2,270				(668	)			77				1,679
Inkai			2,062				(558	)			0				1,504
Key Lake			622				0				0				622
McArthur River			153,327				(12,990	)			2,975				143,312
North Butte-Brown Ranch			1,774				(824	)			420				1,370
Rabbit Lake			279				(150	)			58				187
Smith Ranch-Highland			2,505				(1,953	)			1,817				2,369
Total			220,312				(17,375	)			2,537				205,474
Probable mineral reserves
Cigar Lake			50,950				0				12,112				63,062
Inkai			48,291				(2,834	)			(1,317	)			44,140
McArthur River			98,319				(211	)			(457	)			97,651
North Butte-Brown Ranch			2,030				0				(536	)			1,494
Rabbit Lake			20,049				(4,062	)			(999	)			14,988
Smith Ranch-Highland			2,733				0				(366	)			2,367
Total			222,372				(7,107	)			8,437				223,702
Total mineral reserves			442,684				(24,482	)			10,974				429,176

Notes

 

(1)	Throughput corresponds to mill feed. The difference between 2014 mill feed and Cameco’s share of pounds U3O8 produced in 2014 is due to mill recovery, mill inventory and processing of low-grade material.

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

 

2014 ANNUAL INFORMATION FORM    Page 70

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Mineral resources

As at December 31, 2014 (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)				Content (lbs U3O8)				Cameco’s share (lbs  U3O8)
Cigar Lake		underground			4.7				12.00				1.2				19.6				8.09				3.5				4.7				2.3
Kintyre		open pit															4,315.4				0.58				55.2				55.2				38.7
McArthur River		underground			100.8				3.55				7.9				12.0				10.03				2.7				10.6				7.4
Millennium		underground															1,442.6				2.39				75.9				75.9				53.0
Phoenix		underground															166.4				19.13				70.2				70.2				21.1
Rabbit Lake		underground															1,338.3				0.75				22.2				22.2				22.2
Tamarack		underground															183.8				4.42				17.9				17.9				10.3
Yeelirrie		open pit			24,013.5				0.17				92.4				12,626.5				0.13				34.9				127.3				127.3
Crow Butte		ISR			1,133.1				0.24				6.0				1,354.9				0.29				8.6				14.6				14.6
Gas Hills – Peach		ISR			687.2				0.11				1.7				3,626.1				0.15				11.6				13.3				13.3
Inkai		ISR															31,091.1				0.08				52.2				52.2				30.0
North Butte-Brown Ranch		ISR			232.6				0.08				0.4				5,530.3				0.07				8.4				8.8				8.8
Ruby Ranch		ISR															2,215.3				0.08				4.1				4.1				4.1
Shirley Basin		ISR			89.2				0.16				0.3				1,638.2				0.11				4.1				4.4				4.4
Smith Ranch- Highland		ISR			1,792.1				0.11				4.5				14,378.4				0.05				17.1				21.6				21.6
Total					28,053.2				—				114.4				79,938.9				—				388.4				502.8				379.0

Inferred (tonnes in thousands; pounds in millions)

 

Property		Mining method		Tonnes				Grade % U3O8				Content (lbs U3O8)				Cameco’s share (lbs U3O8)				Notes           ISR – in situ recovery         Mineral resources do not         include amounts that         have been identified as         mineral reserves.         Mineral resources do not         have demonstrated         economic viability.         Totals may not add up         due to rounding.
Cigar Lake		underground			293.7				16.22				105.0				52.5
Kintyre		open pit			950.2				0.46				9.6				6.7
McArthur River		underground			350.9				7.38				57.1				39.9
Millennium		underground			412.4				3.19				29.0				20.2
Phoenix		underground			8.6				5.80				1.1				0.3
Rabbit Lake		underground			2,030.6				0.58				25.9				25.9
Tamarack		underground			45.6				1.02				1.0				0.6
Crow Butte		ISR			1,135.2				0.12				2.9				2.9
Gas Hills- Peach		ISR			3,307.5				0.08				6.0				6.0
Inkai		ISR			253,720.2				0.05				253.8				145.9
North Butte-Brown Ranch		ISR			294.5				0.07				0.4				0.4
Ruby Ranch		ISR			56.2				0.14				0.2				0.2
Shirley Basin		ISR			508.0				0.10				1.1				1.1
Smith Ranch-Highland		ISR			6,989.4				0.05				7.9				7.9
Total					270,103.0				—				501.0				310.6

 

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Changes this year

The table below shows the change in our share of mineral resources for each property in 2014. The change was mostly the result of:

 

•

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

 

•

the removal of the Dawn Lake resources of 7.4 million pounds from our inventory due to uncertainty with the historical drilling data; and

 

•

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

 

(thousands of pounds U3O8)		December 31, 2013				Additions (deletions)				December 31, 2014
Measured mineral resources
Cigar Lake			351				266				617
Crow Butte			6,026				0				6,026
Gas Hills – Peach			9,691				(8,024	)			1,667
McArthur River			7,085				(1,563	)			5,522
North Butte-Brown Branch			0				400				400
Shirley Basin			304				0				304
Smith Ranch-Highland			3,995				486				4,481
Yeelirrie			92,382				0				92,382
Total			119,834				(8,435	)			111,399
Indicated mineral resources
Cigar Lake			761				987				1,748
Crow Butte			8,599				0				8,599
Dawn Lake			7,436				(7,436	)			0
Gas Hills – Peach			12,174				(542	)			11,632
Inkai			28,308				1,683				29,991
Kintyre			38,657				0				38,657
McArthur River			2,409				(550	)			1,859
Millennium			53,040				0				53,040
North Butte – Brown Ranch			10,841				(2,484	)			8,357
Phoenix			15,690				5,370				21,060
Rabbit Lake			20,248				1,929				22,177
Ruby Ranch			4,078				0				4,078
Ruth			2,097				(2,097	)			0
Shirley Basin			4,085				0				4,085
Smith Ranch-Highland			17,756				(701	)			17,055
Tamarack			10,288				0				10,288
Yeelirrie			34,935				0				34,935
Total			271,402				(3,841	)			267,561
Total measured and indicated mineral resources			391,236				(12,276	)			378,960

 

2014 ANNUAL INFORMATION FORM    Page 72

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(thousands of pounds U3O8)		December 31, 2013				Additions (deletions)(1)				December 31, 2014
Inferred mineral resources
Cigar Lake			49,475				3,070				52,545
Crow Butte			2,893				0				2,893
Gas Hills – Peach			874				5,167				6,041
Inkai			146,298				(358	)			145,940
Kintyre			6,719				0				6,719
McArthur River			39,856				16				39,872
Millennium			20,243				0				20,243
North Butte/Brown Ranch			827				(405	)			422
Phoenix			2,280				(1,950	)			330
Rabbit Lake			9,044				16,811				25,855
Ruby Ranch			167				0				167
Ruth			365				(365	)			0
Shirley Basin			1,132				0				1,132
Smith Ranch-Highland			7,878				0				7,878
Tamarack			591				0				591
Total inferred mineral resources			288,642				21,986				310,628

Note

 

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

Key assumptions, parameters and methods

McArthur River

Key assumptions

 

•

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

 

•

Mineral reserves have been estimated with an average allowance of approximately 18% dilution from backfill and mineralized waste mined and a mining recovery of 97.7%. Mineral resources do not include such allowances.

 

•

Mineral resources are estimated at a minimum mineralized thickness of 1.0 metre and at a minimum grade of 0.1% to 0.5% U3O8 assuming underground extraction methods. Mineral reserves are estimated at a cut-off grade of 0.78% U3O8.

 

•

An average uranium price of $70 (US) per pound U3O8 with a $1.00 (US) = $1.05 – 1.10 (Cdn) fixed exchange rate was used to estimate mineral reserves.

Key parameters

 

•

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

 

•

Densities are determined using formulas based on density measurements of drill core and chemical assay grades.

 

•

Mineral reserves at McArthur River are estimated based on the use of raisebore, boxhole and blasthole stope mining methods combined with freeze curtains.

 

•

The production schedule assumes 19.6 million pounds U3O8 (which includes processing downblended material at Key Lake) until 2017. Between 2018 and 2031, an average annual production of 22 million pounds U3O8 is forecast (which includes processing downblended material at Key Lake). Estimated production then begins to decrease in two distinct steps towards the end of the mine life.

Key methods

 

•

Mineral resources were estimated using cross-sectional method and 3-dimensional block models and mineral reserves were estimated with 3-dimensional block models.

 

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•

The models were created from the geological interpretation of section and plan derived from surface and underground drillhole information. Estimates of block grade and density were obtained with ordinary kriging or inverse squared distance methods.

Cigar Lake

Key assumptions

 

•

Mineral resources have been estimated using a minimum mineralization thickness of 1.0 metre and a minimum grade of 1.0% U3O8.

 

•

Mineral reserves have been estimated at a cut-off grade of 2.0% U3O8 and a minimum mineralization thickness of 1.5 metre, after calculating the diluted grade.

 

•

Mineral reserves have been estimated with an allowance of 0.5 metre of dilution material above and below the ore zone, plus approximately 8.5% external dilution at 0% U3O8 and a mining recovery of 90%. Mineral resources do not include such allowances.

 

•

An average uranium price of $70 (US) per pound U3O8 with a $1.00 (US) = $1.05 - $1.10 (Cdn) fixed exchange rate was used to estimate mineral reserves.

Key parameters

 

•

Grades of U3O8 were obtained from chemical assaying of drill core and checked against radiometric probing results. In areas of poor core recovery (< 75%) or missing samples, the grade was determined from probing.

 

•

A correlation between uranium, nickel, cobalt and clay content and density was applied where the density was not directly measured for each sample.

 

•

Mining rates are planned to vary between 100 and 165 tonnes per day during peak production at a full mill production rate of 18 million pounds of U3O8 per year based on 98.5% mill recovery.

Key methods

 

•

The geological interpretation of the orebody outline was done on section and plan views derived from drillhole information. Mineral resources and mineral reserves were estimated using a 3-dimensional block model. Conditional simulation (with simple kriging) and inverse distance squared were used to estimate the grade and density of the different areas.

Inkai

 

•

The estimated mineral resources and reserves at Inkai are located in blocks 1 and 2. No mineral resources or reserves have been estimated for block 3.

 

•

The resource models follow the Kazakhstan State Committee of Mineral Reserves (GKZ) guide and use the Grade-Thickness (GT) estimation method on 2-dimensional blocks in plan. They were created by JSC Volkovgeology, a subsidiary of Kazatomprom which is responsible for prospecting, exploration and development of uranium deposits in Kazakhstan. We performed a validation of the Kazakh reserves estimate for block 1 in 2003, and confirmed the estimated pounds of uranium to within 2.5% of the Kazakh estimate. The Kazakh estimate was also validated by an independent consulting firm in 2005. In 2007, we and an independent consulting firm verified the block 2 Kazakh mineral reserves estimate and obtained results that were consistent with the Kazakh estimate.

 

•

Historic drilling pattern densities over blocks 1 and 2 were sufficient to satisfy the Kazakhstan State Reserve Commission requirements in defining reserves in the C2, C1 and B categories within block 1 and C2 and C1 categories within block 2.

 

•

Our reconciliation of the Kazakh classification system to the CIM standard definitions are set out in Section 6.3 (Table 6-4) of the Inkai technical report. We correlate Kazakhstan’s reserves categories B, C1 and C2 to NI 43-101 mineral resource categories of measured, indicated and inferred.

Key assumptions

 

•

Dilution and mining loss are not relevant factors because Inkai uses in situ recovery as the uranium extraction method. The recovery obtained from the in situ leaching process is included in the metallurgical recovery.

 

•

Mineral reserves have been estimated at a minimum grade-thickness of 0.130 m% U3O8.

 

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Key parameters

 

•

Grades (%U3O8) were obtained from downhole gamma radiometric probing of drillholes, checked against assay results and prompt-fission neutron probing results in order to account for disequilibrium.

 

•

An average density of 1.70 t/m3 was used, based on historical and current sample measurements.

 

•

In situ recovery production rates are planned to vary between 13,000 and 16,000 lbs U3O8 per day at a full mill production rate of 5.2 million lbs of U3O8 per year based on 85% recovery.

Key methods

 

•

The geological interpretation of the orebody outline was done on section and plan views derived from drillhole and core information.

 

•

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

Sustainable development

We want to bring the multiple benefits of clean, safe and reliable nuclear energy to the world, and are committed to delivering our products responsibly.

For us, sustainable development is a management philosophy and process that helps us:

 

•

build trust, credibility and corporate reputation

 

•

gain and protect community support to operate and grow

 

•

attract and retain employees

 

•

manage risk

 

•

drive innovation and continual improvement to build competitive advantage.

Rather than viewing sustainable development as an “add-on” to traditional business activity, we see it as an integral component to the way we do business. We aim to integrate sustainable development principles and practices at each level of our operations, including featuring them in our objectives and our approach to compensation.

We have developed a corporate social responsibility policy (CSR policy) that defines our standards and expectations for sustainable development throughout the company. Under the CSR policy:

 

•

our goal is to be recognized as a leader in corporate social responsibility by proactively addressing the social, environmental and financial aspects of our business with key stakeholders; and

 

•

we seek to integrate corporate social responsibility in our day to day business, and achieve strong performance in our four key measures of success: a safe, healthy and rewarding workplace, a clean environment, supportive communities and outstanding financial performance.

We seek to implement our CSR policy by including commitments based upon these four key measures of success:

Safe, healthy and rewarding workplace

We are committed to having a safe, healthy and rewarding workplace that reflects the diversity of the communities in which we operate. One of the ways we implement this commitment is through our safety, health, environment and quality policy. See Safety, Health and Environment starting at page 76 for more information about this policy.

Clean environment

We are committed to continually improving our overall environmental performance throughout the lifecycle of our operations. See Safety, Health and Environment starting at page 76 for how we implement this commitment.

 

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Supportive communities

We are committed to building long-lasting and trusting relationships with the communities in which we operate. One of the ways we implement this commitment is through our Five Pillar CSR Strategy, which is described below.

Outstanding financial performance

We are committed to managing our business in a way that ensures long term financial stability and profitability.

Our CSR policy describes further what we do to implement these commitments.

Our chief executive officer is responsible for ensuring compliance with our CSR policy and implementation of its supporting policies and programs.

Five Pillar CSR Strategy

Over more than 25 years of operation and partnership in northern Saskatchewan, we have developed a comprehensive Five Pillar CSR Strategy aimed at ensuring the support of the communities with whom we work, all across our operations globally. The strategy is flexible and is implemented by our global operations at a local level to reflect the needs of the local communities.

While developed in part as a result of some of the socio-economic obligations that are contained in our surface lease agreements with the Saskatchewan government, the bulk of the strategy has evolved as a result of the commercial benefits we see from ensuring strong support among local communities wherever we operate. The pillars are:

1. The Workforce Development pillar delivers programming that aims to build educational and skills capacity in local communities. The goal of this pillar is to ensure that students stay in school, have the means to attend post-secondary education, and receive training to facilitate employment opportunities in our industry.

2. The Business Development pillar is designed to promote the involvement of locally-owned businesses in contracting opportunities at our operations, and to provide additional jobs, revenue streams and capacity building at the local community level. We work with local contractors in a variety of ways, including by providing updates on contracting opportunities. In northern Saskatchewan, we also have a Northern Preferred Supplier program, which gives preference to majority-owned northern companies and helps to build a long-term relationship between northern contractors and ourselves.

3. The Community Engagement pillar is designed with the objective to ensure that we secure support for our operations from local communities and satisfy the obligations placed on us by regulators and laws. While the main activities here are focused specifically on the communities in closest proximity to our operations, in northern Saskatchewan, we also ensure that the greater region is kept informed of our operations, whether it is through our yearly community tours or community focused websites.

4. The Community Investment pillar is designed to help local communities with much-needed funding for community programming and infrastructure. Through this pillar, we look to support community initiatives that are focused on youth, education and literacy, health and wellness and community development.

5. The Environmental Stewardship pillar, the most recent addition to the strategy, is designed to support our overall environmental programming. It is intended to provide communities with a voice in both the formal environmental assessment regulatory process, as well as ongoing monitoring activities.

Safety, Health and Environment

We introduced our safety, health, environment and quality policy in 1991, and have refined our approach over the years to form our overall integrated SHEQ management system.

The SHEQ policy includes our statement of principles and identifies the seven programs that comprise the SHEQ management system, which implements the policy and supports these principles.

 

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Our principles

 

•

prevent injury, ill health and pollution

 

•

comply with and move beyond legal and other requirements

 

•

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

 

•

ensure quality of processes, products and services

 

•

continually improve our overall performance.

SHEQ management system

The seven programs that comprise Cameco’s SHEQ management system are as follows:

 

•

Quality management program

 

•

Safety and health management program

 

•

Radiation protection program

 

•

Environmental management program

 

•

Management system audit program

 

•

Emergency preparedness and response program

 

•

Contractor management program.

We benchmark our system against those used by other companies in the mining and nuclear power generation sectors. On behalf of the board, the safety, health and environment committee oversees our SHEQ policy and management system as well as our safety and environmental performance. Our chief executive officer is responsible for ensuring this system is established and maintained across the company.

Our SHEQ management system is centralized and managed at the corporate level. It is implemented across the corporation as a whole with a focus on our operations.

Corporate SHEQ activity at the operations focuses on consistent application of programs and procedures, and providing help with identified issues. Each of our sites is responsible for conducting internal audits to make sure their programs meet Cameco standards and comply with regulatory requirements. The SHEQ management system is also part of our program to manage environmental risks at the operations and meet the requirements of ISO 14001. All of our operating sites are ISO 14001 certified.

In 2014, we invested:

 

•

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

 

•

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

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

There were no environmentally significant incidents in 2013 or 2014.

In 2014, we continued to achieve strong safety performance at our operations.

Focus on the environment

Our business by its nature has an impact on the environment, so environmental performance is a key area of focus for us.

Our focus in this regard is reinforced by our systematic approach to safety, health, environment and quality (SHEQ) issues. We have integrated this approach into activities at our operating properties and our planning process for major projects. We also have conceptual decommissioning plans in place for all of our operating sites.

We report our performance annually. You can find this information on our website (cameco.com) and in our sustainable development report, which is also available on our website.

 

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Reducing our impact

We have been carrying out our long-term plan to reduce the impact we have on the environment. This includes assessing, monitoring and reducing our effect on air, water and land and optimizing the amount of energy we consume, and managing the effects of waste.

We are investing in management systems and safety initiatives to achieve operational excellence and reliability, and this continues to improve our safety and environmental performance and operating efficiency. We have also incorporated life cycle value assessment (LCVA) into our project management and engineering processes to ensure social, environmental and financial risks have been more fully considered when designing new facilities.

Like other large industrial organizations, we use chemicals in our operations that could be hazardous to our health and the environment if they are not handled correctly. We train our employees in the proper use of hazardous substances and in emergency response techniques.

We work with communities who are affected by our activities to tell them what we are doing and to receive feedback and further input, to build and sustain their trust. In Saskatchewan, we participate in the Athabasca Working Group and Northern Saskatchewan Environmental Quality Committee.

In Ontario, we liaise with the community by regularly holding educational and environment-focused activities including through our Community Forum series, our major presence at the Port Hope Fair, our regular community newsletters and ongoing communication with local elected officials and community leaders.

Land

Cameco’s North American operating sites affect a relatively small area compared to what would be required to generate the same amount of energy using other technologies.

Our mines in northern Saskatchewan are underground mines so the impact on the surface land is minimal. We use ISR mining in the U.S. to extract uranium from underground non-potable, brackish aquifers, so the impact on the surface there is also minimal.

Water

We look to improve processes and adopt new technologies to improve how we manage process water, and the effect it has on receiving water bodies.

We have taken measures that have been successful in improving the quality of our treated effluent in northern Saskatchewan with a focus on molybdenum, selenium and uranium. Through the addition of treatment circuits at Key Lake and Rabbit Lake and optimization at McArthur River, we have achieved a 70% reduction in loadings of molybdenum to the receiving environment from these three operations. With regard to selenium loadings, those same improvements have also been effective in achieving about a 50% decrease in total loadings. We have also achieved a more than 50% decrease in uranium loadings to the environment from the three operations. Even with these achievements, we are focusing on maintaining our excellent water quality while increasing production at our facilities.

We monitor the environment to verify that the improvements we made in the mill effluent treatment process are having the planned effect of reducing the impact on the receiving environment.

Fuel Services

All fuel services sites have environmental management systems that are ISO 14001 registered. Continuous improvement is a key aspect of the management systems and in 2013 the fuel services division advanced its focus on improving environmental performance at all three sites. For example, at the conversion facility, the Uranium in Air Reduction Focus Team updated the Air Emission Management Strategy in 2014 to include a Uranium in Air five year reduction target of at least 50% from 2012 emissions. With focused improvements, emissions are on track to meet the newly established objective.

 

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United States

The ISR method we use in the US involves extracting uranium from underground non-potable aquifers by dissolving the uranium with a carbonate-based water solution and pumping it to a processing facility on the surface. After mining has been completed, an ISR wellfield must be restored according to regulatory requirements. This generally involves restoring the groundwater to its pre-mining state or equivalent class of use water standard. In the US, we are not only working to improve the groundwater restoration process, but also on waste reduction programs.

We have 10 wellfields under restoration. See page 81 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.

 

		2014				2013				2012
Greenhouse gas emissions(1) of tonnes of CO2 equivalent (CO2e)			559,600	(2)			519,589				532,497

Note:

 

(1)	Greenhouse gas emissions include carbon dioxide, methane, nitrous oxide, sulphur hexafluoride, hydrofluorocarbons (HFCs), and perfluorocarbons (PFCs) expressed as a carbon equivalent (CO2e).

(2)	This number is a preliminary estimate and the final number will be available in our 2015 sustainable development report.

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

Port Hope

In 2011, we lowered emissions of uranium and hydrofluoric acid to the air by installing new equipment and changing the operating procedures. Our fuel services division has since focused on improving the monitoring of some emission sources and in 2014 established a process for setting an objective for reducing uranium in air emissions.

McArthur River

McArthur River has a large refrigeration plant that produces cold brine used for freezing the area of the deposit to be mined. The plant uses refrigerants, but they are not ozone-depleting chemicals that harm the earth’s atmosphere.

 

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Cigar Lake

Cigar Lake has a large refrigeration plant that produces cold brine used for freezing the area of the deposit to be mined. 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, the new acid plant has significantly reduced emissions to air. The new calciner will significantly reduce emissions from that circuit as well.

Rabbit Lake

While our current emissions meet all regulatory requirements, substantial upgrades to the acid plant at Rabbit Lake have resulted in more than a 60% reduction in the mean SO₂ stack emissions (to 85 kg/day from 300 kg/day).

Waste

Our mines and mills in northern Saskatchewan account for most of the tailings and waste rock our operations generate.

We treat the mill tailings at Rabbit Lake and Key Lake to stabilize contaminants before depositing them in tailings management facilities (in mined-out open pits near the mills).

We divert groundwater and surface water around the tailings management facilities, monitor the water to make sure it is not impacted by the tailings, and treat it if necessary. We monitor runoff and treat water from waste rock piles as needed. We stockpile some waste rock to blend with higher grade ores. We contour other waste rock piles and revegetate them before decommissioning the site. We plan to continue to monitor groundwater after the facility has been decommissioned.

Complying with environmental regulations

Our business is required to comply with laws and regulations that are designed to protect the environment and control the management of hazardous wastes and materials. Some laws and regulations focus on environmental issues in general, and others are specifically related to mining and the nuclear sector. They change often, with requirements increasing, and existing standards are being applied more stringently. While this dynamic promotes continuous improvement, it can increase expenses and capital expenditures, or limit or delay our activities.

Government legislation and regulation in various jurisdictions establish standards for system performance, standards, objectives and guidelines for air and water quality emissions, and other design or operational requirements for the various SHEQ components of our operations and the mines that we plan to develop. In addition, we must complete an environmental assessment before we begin developing a new mine or start processing activities, or make any significant change to our operations. Once we have permanently stopped mining and processing activities, we are required to decommission and reclaim the operating site to the satisfaction of the regulators, and we may be required to actively manage former mining properties for many years.

Canada

Not only is there ongoing regulatory oversight by the Canadian Nuclear Safety Commission (CNSC), the Saskatchewan Ministry of the Environment, the Ontario Ministry of the Environment, and Environment Canada, but there is also public scrutiny of the impact our operations have on the environment.

The CNSC, an independent regulatory authority established by the federal government under the Nuclear Safety and Control Act (NSCA), is our main federal regulator in Canada. It regulates our compliance with the NSCA and is the federal lead for environmental assessments required to be carried out under the Canadian Environmental Assessment Act, 2012, which was introduced as part of the federal government’s responsible resource development policy.

 

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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.

Our plans to expand production or build new mines in Saskatchewan are subject to this process. 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:

 

 

Improving our environmental performance is challenging and we have a number of activities underway:

 

•

improving uranium emissions from different systems at the Port Hope conversion facility to meet the newly established objective

 

•

focusing on maintaining our excellent water quality while increasing production at our facilities.

Efforts like these often require additional environmental studies near the operations, and we will continue to undertake these as required.

It can take a significant amount of time for regulators to make requested changes to a licence or grant a requested approval because the activity may require an environmental assessment or an extensive review of supporting technical data, management programs and procedures. We are improving the quality of our proposals and submissions and have introduced a number of programs to ensure we continue to comply with regulatory requirements, but this has also increased our capital expenditures and our operating costs.

As our SHEQ management system matures, regulators review our programs and recommend ways to improve our SHEQ performance. These recommendations are generally procedural and do not involve large capital costs, although systems applications can be significant and result in higher operating costs.

We believe that regulatory expectations of the CNSC and other federal and provincial regulators will continue to evolve, and lead to changes to both requirements and the regulatory framework. This will likely increase our expenses.

United States

Our ISR operations in the US have to meet federal, state and local regulations governing air emissions, water discharges, handling and disposal of hazardous materials and site reclamation, among other things.

Mining activities have to meet comprehensive environmental regulations from the US Nuclear Regulatory Commission (NRC), Bureau of Land Management, Environmental Protection Agency and state environmental agencies. The process of obtaining mine permits and licences generally takes several years, and involves environmental assessment reports, public hearings and comments. We have the permits and licences for the US operations that we need to meet our 2015 production plans.

After mining is complete, ISR wellfields have to be restored according to regulatory requirements. This generally involves restoring the groundwater to its pre-mining state or equivalent class of use water standard. Restoration of Crow Butte wellfields is regulated by the Nebraska Department of Environmental Quality and the NRC. Restoration of Smith Ranch-Highland wellfields is regulated by the Wyoming Department of Environmental Quality and the NRC. See page 84 for the status of wellfield restoration and regulatory approvals.

 

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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. In November 2014, the law of the Republic of Kazakhstan on notifications and permits was enacted and replaced the existing law on licensing. Among others, this new legislation provides for terms and procedures for obtaining an environmental emissions permit.

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.

Under the Ecological Code, Inkai needs an environmental permit to operate. The permit certifies the holder’s right to discharge emissions into the environment, provided that it introduces the “best available technologies” and complies with the technical guidelines in the code. Inkai has a permit for environmental emissions and discharges, valid until December 2016 and an emissions permit for drilling activities, valid until December 2016. It also holds the required permits under the Water Code.

Government authorities and the courts enforce compliance with these permits, and violations can result in the imposition of administrative, civil or criminal penalties, the suspension or stopping of operations, orders to pay compensation, orders to remedy the effects of violations and orders to take preventive steps against possible future violations. In certain situations, the issuing authority may suspend or revoke the permits.

Inkai has environmental insurance, as required by the Ecological Code and the resource use contract. Inkai also has voluntary civil liability insurance for environment protection.

Nuclear waste management and decommissioning

Once we have permanently stopped mining and processing activities, we are required to decommission the operating sites. This includes reclaiming all waste rock and tailings management facilities and the other areas of the site affected by our activities to the satisfaction of regulatory authorities.

Estimating decommissioning and reclamation costs

We develop conceptual decommissioning plans for our operating sites and use them to estimate our decommissioning costs. We also submit them to regulators to determine the amount of financial assurance we must provide to secure our decommissioning obligations. Our plans include reclamation techniques that we believe generate reasonable environmental and radiological performance. Regulators give “conceptual approval” to a decommissioning plan if they believe the concept is reasonable.

We started conducting reviews of our conceptual decommissioning plans for all Canadian sites in 1996. We typically review them every five years, or when we amend or renew an operating licence. We review our cost estimates for both accounting purposes and licence applications. For our US sites, they are reviewed annually. A preliminary decommissioning plan has been established for Inkai. The plan is updated every five years or as significant changes take place, which would affect the decommissioning estimate.

 

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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 2014, our estimate of total decommissioning and reclamation costs was $874 million. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $828 million at the end of 2014 (the present value of the $874 million). Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, our expected costs for decommissioning and reclamation for the next five years are not material.

We provide financial assurances for decommissioning and reclamation as letters of credit to regulatory authorities, as required. We had a total of $911 million in letters of credit supporting our reclamation liabilities at the end of 2014. All of our North American operations have letters of credit in place that provide financial assurance in connection with our preliminary plans for decommissioning for the sites.

Please also see note 18 to the 2014 financial statements for our estimate of decommissioning and reclamation costs and related letters of credit.

Canada

 

Decommissioning estimates
(100% basis)
McArthur River		$	48 million
Rabbit Lake		$	203 million
Key Lake		$	218 million
Cigar Lake		$	49 million

As part of the licensing process in 2013 for McArthur River, Rabbit Lake, Key Lake and Cigar Lake, the preliminary decommissioning plans for each facility were updated and submitted to the CNSC staff. Our Key Lake decommissioning estimate was further revised and submitted to the CNSC in 2014 and we received final approval of the decommissioning estimate from the CNSC in January 2015. Letters of credit for McArthur River, Rabbit Lake, and Cigar Lake are in place and reflect the current decommissioning cost estimate. The letters of credit for the current Key Lake decommissioning cost estimate are in the process of being updated.

The reclamation and remediation activities associated with waste rock and tailings from processing Cigar Lake ore and uranium solution are covered in the plans and cost estimates for the facility that will be processing it.

 

Decommissioning estimates
(100% basis)
Port Hope		$	102 million
Blind River		$	39 million
CFM		$	20 million

We renewed our licences for Port Hope, Blind River and CFM in 2012. As part of that process, in 2011, the preliminary decommissioning plans for each facility were accepted by the CNSC staff and all three letters of credit were updated in April 2012 after the licence renewals were granted.

Historical waste

When Cameco was formed, we assumed ownership and primary responsibility for managing the waste already existing at the time of the reorganization. This historical waste was all in Ontario, at the historical facilities, which include the Port Hope Conversion Facility, Blind River Refinery, Port Granby Waste Management Facility, Welcome Waste Management Facility and the Centre Pier in Port Hope.

In March 2004, we reached an agreement to transfer two historical facilities and their associated liabilities to the Government of Canada: the Welcome Waste Management Facility and the Port Granby Waste Management

 

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Facility. We transferred the Welcome Waste Management Facility and the Port Granby Waste Management Facility to Natural Resources Canada on March 31, 2010 and March 29, 2012, respectively.

In March 2012, we entered into a settlement with Canada Eldor Inc., the entity established by the federal government to assume the historical liabilities and obligations of Eldorado Nuclear Limited, regarding liability for historical waste located at the historical facilities. We are now responsible for all liabilities and costs and expenses related to historical waste and the remaining historical facilities owned or leased by us, which are the Port Hope Conversion Facility, the Blind River Refinery and the Centre Pier in Port Hope.

Recycling uranium byproducts

We have an agreement to process certain uranium-bearing byproducts from Blind River and Port Hope at the White Mesa mill in Blanding, Utah. While this arrangement addresses existing inventory and current recycling requirements, we are considering other outlets.

For example, in 2001, we tested recycling the byproducts at our Key Lake mill, and in 2002 submitted a proposal to federal and provincial regulatory authorities for approval to proceed. We received regulatory approval from the Saskatchewan government in 2003, and were advised by the CNSC in 2011 that this project can proceed. Recycled byproduct material continued to be successfully processed at Key Lake in 2014. Processing of this material will be increased in 2015 at the Key Lake mill.

United States

After mining has been completed, an ISR wellfield has to be restored according to regulatory requirements. This generally involves restoring the groundwater to its pre-mining state or equivalent class of water standard.

For wellfield restoration to be complete, regulatory approval is required. It is difficult for us to estimate the timing for wellfield restoration due to the uncertainty in timing for receiving final regulatory approval.

Crow Butte

Restoration of Crow Butte wellfields is regulated by the Nebraska Department of Environmental Quality and the NRC. There are five wellfields being restored at Crow Butte. The groundwater at mine unit #1 has been restored to pre-mining quality standards, all wells are plugged and the piping removed.

Our estimated cost of decommissioning the property is $45.4 million (US). We have provided the State of Nebraska with a $44.7 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 $45.4 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 unit A and mine unit B) that have been fully restored.

The restoration of mine unit B has been approved by the Wyoming Department of Environmental Quality, and we will need to submit an application for an Alternate Concentration Limit to the NRC for approval.

Our estimated cost of decommissioning the property is $220 million (US), including North Butte. We have provided the State of Wyoming with $282 million (US) in letters of credit as security for decommissioning the property, and are in the process of receiving regulatory approval to decrease the letters of credit to $240 million (US), in accordance with the State of Wyoming’s requirements.

Kazakhstan

Inkai is subject to decommissioning liabilities, largely defined by the terms of the resource use contract. Inkai has established a separate bank account and made the required contributions to the account as security for

 

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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 $9 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 79 for additional details.

The regulatory environment

This section, and the section Complying with environmental regulations starting on page 80, discuss some of the more significant government controls and regulations that have a material effect on our business. A significant part of our economic value depends on our ability to comply with the extensive and complex laws and regulations that govern our activities. We are not aware of any proposed legislation or changes to existing legislation that could have a material effect on our business.

International treaty on the non-proliferation of nuclear weapons

The Treaty on the Non-Proliferation of Nuclear Weapons (NPT) is an international treaty that was established in 1970. It has three objectives:

 

•

to prevent the spread of nuclear weapons and weapons technology

 

•

to foster the peaceful uses of nuclear energy

 

•

to further the goal of achieving general and complete disarmament.

The NPT establishes a safeguards system under the responsibility of the International Atomic Energy Agency. Almost all countries are signatories to the NPT, including Canada, the US, the United Kingdom and France. We are therefore subject to the NPT and comply with the International Atomic Energy Agency’s requirements.

Industry regulation and permits

Canada

Our Canadian operations have regulatory obligations to both the federal and provincial governments. There are four main regulatory agencies that issue licences and approvals:

 

•

CNSC (federal)

 

•

Fisheries and Oceans Canada (federal)

 

•

Saskatchewan Ministry of Environment

 

•

Ontario Ministry of Environment.

Environment Canada (federal) is also a main regulatory agency, but does not issue licences and approvals.

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.

 

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Mine ownership restrictions

The federal government has instituted a policy that restricts ownership of Canadian uranium mining properties to:

 

•

a minimum of 51% ownership by residents

 

•

a basic maximum limit of 49% ownership by non-residents of uranium properties at the first stage of production.

The government may grant exceptions. For example, resident ownership may be less than 51% if the property is Canadian-controlled. Exceptions will only be granted in cases where it is demonstrated that Canadian partners cannot be found, and it must receive Cabinet approval.

The government issued a letter to the Canadian uranium industry on December 23, 1987, outlining the details of this ownership policy. On March 3, 2010, the government announced its intention to liberalize the foreign investment restrictions on Canada’s uranium mining sector to “ensure that unnecessary regulation does not inhibit the growth of Canada’s uranium mining industry by unduly restricting foreign investment”. After striking an expert panel to study the issue and soliciting feedback from various stakeholders, the federal government stated in October 2011 that it would not be changing the policy.

In 2013, it was announced that the proposed Canada-EU Trade Agreement (CETA) contemplates that the Canadian uranium mine ownership requirement would be waived for all European companies. However, at this time CETA has not yet been ratified and remains an agreement in principle and this waiver will not come into effect until such time as CETA is ratified and implemented.

Cameco ownership restriction

We are subject to ownership restrictions under the Eldorado Nuclear Limited Reorganization and Divestiture Act, which restricts the issue, transfer and ownership, including joint ownership, of Cameco shares to prevent both residents and non-residents of Canada from owning or controlling more than a certain percentage of shares. See pages 115 and 116 for more information.

Industry governance

The Nuclear Safety and Control Act (NSCA) is the primary federal legislation governing the control of the mining, extraction, processing, use and export of uranium in Canada. It authorizes the CNSC to make regulations governing all aspects of the development and application of nuclear energy, including uranium mining, milling, conversion, fuel fabrication and transportation. It grants the CNSC licensing authority. A person may only possess or dispose of nuclear substances and build, operate and decommission its nuclear facilities according to the terms and conditions of a CNSC licence. Licensees must satisfy specific conditions of the licence in order to maintain the right to operate their nuclear facilities.

The NSCA emphasizes the importance of environmental as well as health and safety matters, and requires licence applicants and licensees to have adequate provisions for protection.

Regulations made under the NSCA include those dealing with the specific licence requirements of facilities, radiation protection, physical security for all nuclear facilities and the transport of radioactive materials. The CNSC has also issued regulatory documents to assist licensees in complying with regulatory requirements, such as decommissioning, emergency planning, and optimizing radiation protection measures.

All of our Canadian operations are governed primarily by licences granted by the CNSC and are subject to all federal statutes and regulations that apply to us, and all the laws that generally apply in the province where the operation is located, unless there is a conflict with the terms and conditions of the licence or the federal laws that apply to us.

Uranium export

We must secure export licences and export permits from the CNSC and the Department of Foreign Affairs and International Trade in order to export our uranium. These arrangements are governed by the bi-lateral and multi-lateral agreements that are in place between governments.

 

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Land tenure

Most of our uranium reserves and resources are located in the province of Saskatchewan:

 

•

a mineral claim from the province gives us the right to explore for minerals (other government approvals are required to carry out surface exploration)

 

•

a crown lease with the province gives us the right to mine the minerals on the property

 

•

a surface lease with the province gives us the right to use the land for surface facilities and mine shafts while mining and reclaiming the land.

A mineral claim has a term of two years, with the right to renew for successive one-year periods. Generally, the holder has to spend a certain amount on exploration to keep the mineral claim in good standing. If we spend more than the amount required, the extra amount can be applied to future years.

A holder of a mineral claim in good standing has the right to convert it into a crown lease. A crown lease is for 10 years, with a right to renew for additional 10-year terms. The lessee must spend a certain amount on work during each year of the crown lease. The lease cannot be terminated unless the lessee defaults on any terms of the lease, or under any provisions of The Crown Minerals Act (Saskatchewan) or regulations under it, including any prescribed environmental concerns. Crown leases can be amended unilaterally by the lessor by an amendment to The Crown Minerals Act (Saskatchewan) or The Mineral Disposition Regulations, 1986 (Saskatchewan).

A surface lease can be for up to 33 years, as necessary for operating the mine and reclaiming the land. The province also uses surface leases to specify other requirements relating to environmental and radiation protection as well as socioeconomic objectives.

United States

Uranium industry regulation

In the US, uranium recovery is regulated primarily by the NRC according to the Atomic Energy Act of 1954, as amended. Its primary function is to:

 

•

ensure employees, the public and the environment are protected from radioactive materials

 

•

regulate most aspects of the uranium recovery process.

The NRC’s regulations for uranium recovery facilities are codified in Title 10 of the Code of Federal Regulations (10 CFR). It issues Domestic Source Material Licences under 10 CFR, Part 40. The National Environmental Policy Act (NEPA) governs the review of licence applications, which is implemented through 10 CFR, Part 51.

At Smith Ranch-Highland and Crow Butte, safety is regulated by the federal Occupational Safety and Health Administration.

Other governmental agencies are also involved in the regulation of the uranium recovery industry.

The NRC also regulates the export of uranium from the US and the transport of nuclear materials within the US. It does not review or approve specific sales contracts. It also grants export licences to ship uranium outside the US.

Wyoming

The uranium recovery industry is also regulated by the Wyoming Department of Environmental Quality, the Land Quality Division according to the Wyoming Environmental Quality Act (WEQA) and the Land Quality Division Non-Coal Rules and Regulations under the WEQA. According to the state act, the Wyoming Department of Environmental Quality issues a permit to mine. The Land Quality Division administers the permit.

The state also administers a number of Environmental Protection Agency (EPA) programs under the Clean Air Act and the Clean Water Act. Some of the programs, like the Underground Injection Control Regulations, are incorporated in the Land Quality Division Non-Coal Rules and Regulations. Wyoming currently requires wellfield decommissioning to the standard of pre-mining use.

 

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Nebraska

The uranium recovery industry is regulated by the NRC, and the Nebraska Department of Environmental Quality according to the Nebraska Environmental Protection Act. The Nebraska Department of Environmental Quality issues a permit to mine. The state requires wellfield groundwater be restored to the class of use water standard.

Land tenure

Our uranium reserves and resources in the US are held by subsidiaries that are located in Wyoming and Nebraska. The right to mine or develop minerals is acquired either by leases from the owners (private parties or the state) or mining claims located on property owned by the US federal government. Our subsidiaries acquire surface leases that allow them to install wellfields and conduct ISR mining.

Kazakhstan

See Kazakhstan government and legislation starting on page 50.

Taxes and Royalties

Transfer pricing disputes

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

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

 

•

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

 

•

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

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

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

CRA dispute

Since 2008, CRA has disputed our corporate structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2009 tax returns. We have recorded a cumulative tax provision of $85 million, where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts

 

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for the period from 2003 through 2014. We continue to believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

We are confident that we will be successful in our case; however, for the years 2003 through 2009, CRA issued notices of reassessment for approximately $2.8 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $820 million. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229 million. The Canadian income tax rules include provisions that generally require larger companies like us to remit 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions and tax loss carryovers, we have paid a net amount of $248 million cash to the Government of Canada, which includes the amounts shown in the table below. As an alternative to paying cash, we are exploring the possibility of providing security in the form of letters of credit to satisfy our requirements under these provisions.

 

YEAR PAID ($ MILLIONS)		CASH TAXES				INTEREST AND INSTALMENT PENALTIES				TRANSFER PRICING PENALTIES				TOTAL
Prior to 2013			—				13				—				13
2013			1				9				36				46
2014			106				47				—				153
2015			(43	)			1				78				36
Total			64				70				114				248

In addition to the cash payments indicated above, we have also provided letters of credit to the Ontario Ministry of Finance related to reassessments for 2007 and 2008 income tax and arrears interest totaling $7 million. Using the methodology we believe CRA will continue to apply, and including the $2.8 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $6.6 billion of additional income taxable in Canada for the years 2003 through 2014, which would result in a related tax expense of approximately $1.9 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2009. As a result, we estimate that cash taxes and transfer pricing penalties for these years would be between $1.45 billion and $1.5 billion. In addition, we estimate there would be interest and instalment penalties applied that would be material to us. While in dispute, we would generally be responsible for remitting or otherwise providing security for 50% of the cash taxes and transfer pricing penalties (between $725 million and $750 million), plus related interest and instalment penalties assessed, which would be material to us.

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

 

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

 

1	These amounts do not include interest and instalment penalties, which totalled approximately $70 million to date.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to the Government of Canada, including the $248 million already paid to date.

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

IRS dispute

As noted above, we received a RAR (also commonly referred to as a 30-Day Letter) from the IRS pertaining to the 2009 tax year for certain of our US subsidiaries. The RAR proposes an increase in taxable income in the US of approximately $108 million (US) for the 2009 taxation year with a corresponding increased income tax

 

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expense, as calculated by the IRS, of approximately $35 million (US). The IRS proposes penalties of approximately $7 million (US). Interest would also be charged on the amounts owing.

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

 

•

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

 

•

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

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

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

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

Overview of disputes

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

 

		CRA		IRS
Basis for dispute		•       Corporate structure/governance   •       Transfer pricing methodology used for certain intercompany uranium sale and purchase agreements   •       Allocates Cameco Europe Ltd. (CEL) income (as adjusted) for 2003 through 2009 to Canada (same income we paid tax on in foreign jurisdictions and includes income that IRS is proposing to tax)		•       Income earned on sales of uranium by the US mines to CEL is inadequate   •       Compensation earned by Cameco Inc., one of our US subsidiaries, is inadequate   •       Allocates a portion of CEL’s 2009 income to the US (a portion of the same income we paid tax on in foreign jurisdictions and which the CRA is proposing to tax)
Years under consideration		•       CRA reassessed 2003 to 2009   •       Auditing 2010 to 2012		•       IRS issued Revenue Agent’s Report for 2009   •       Auditing 2010 to 2012
Timing of resolution		•       Expect our appeal of the 2003 reassessment to be heard in the Tax Court in 2016   •       Expect Tax Court decision six to 18 months after completion of trial		•       Plan to contest proposed adjustments in an administrative appeal   •       This dispute is at an early stage, and we cannot yet provide an estimate as to the timeline for resolution
		CRA		IRS
Required payments		•       Expect to remit 50% of cash taxes, interest and penalties as reassessed   •       Paid $248 million in cash to date   •       Exploring possibility of providing security in the form of letters of credit to satisfy required remittances		•       No payments required while under administrative appeal

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

This discussion of our expectations relating to our tax disputes with CRA and IRS and future tax reassessments by CRA and IRS is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the

 

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heading Caution about forward-looking information beginning on page 2 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.

Assumptions

 

Material risks that could cause actual results to differ materially

 

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Canadian royalties

We pay royalties to the province of Saskatchewan under the terms of Part III of the Crown Mineral Royalty Regulations pursuant to the Crown Minerals Act. Royalties apply to the sale of all uranium extracted from orebodies in the province.

Two types of royalties are paid:

 

•

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

 

•

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

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

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

Canadian income taxes

We are subject to federal income tax and provincial taxes in Saskatchewan and Ontario. Current income tax recovery for 2014 was $2.9 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 are eligible for a manufacturing and processing tax credit.

US taxes

Our subsidiaries in Wyoming and Nebraska pay severance taxes, property taxes and Ad Valorem taxes in those states. They incurred $5.4 million (US) in taxes in 2014.

Our US subsidiaries are subject to US federal and state income tax. They may also be subject to the Alternative Minimum Tax (AMT) at a rate of 20%. We can carry forward AMT paid in prior years indefinitely, and apply it as credit against future regular income taxes.

Kazakhstan taxes

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

On January 1, 2009, a new tax code of the Republic of Kazakhstan went into effect that includes a number of changes to the taxation regime of subsoil users. The most significant changes involve eliminating the stable tax regime, imposing a mineral extraction tax and changing the payment rate for commercial discovery.

Tax stabilization eliminated

In October 2009, at the request of the Kazakhstan Ministry of Energy and Mineral Resources, Inkai signed an amendment to the resource use contract to adopt the new tax code, eliminating the tax stabilization provision. While we do not expect this to have a material impact on Inkai at this time, eliminating the tax stabilization provision could be material in the future. See page 49 for more information about the resource use contract.

Corporate income tax rate

Inkai is subject to corporate income tax at a rate of 20%.

Mineral extraction tax

The tax code includes a Tax on Production of Useful Minerals, a mineral extraction tax replacing the previous royalty. The mineral extraction tax must be paid on each type of mineral and certain other substances that are extracted. The rate used to calculate the mineral extraction tax on uranium is currently 18.5%.

 

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Payment for commercial discovery

Under the resource use contract, a one-time commercial discovery bonus of 0.05% of the value of Kazakh-defined recoverable reserves is paid when there is confirmation that Kazakh-defined recoverable reserves are located in a particular licence area. Under the tax code, the rate increased to 0.1%.

Excess profits tax

The tax code has changed the calculation of excess profits tax. Inkai believes it will not have to pay this tax for the foreseeable future.

 

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Risks that can affect our business

There are risks in every business.

The nature of our business means we face many kinds of risks and hazards – some that relate to the nuclear energy industry in general, and others that apply to specific properties, operations or planned operations. These risks could have a significant impact on our business, earnings, cash flows, financial condition, results of operations or prospects.

The following section describes the risks that are most material to our business. This is not, however, a complete list of the potential risks we face – there may be others we are not aware of, or risks we feel are not material today that could become material in the future. Our risk policy and process involves a broad, systematic approach to identifying, assessing, reporting and managing the significant risks we face in our business and operations. However, 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 2014 MD&A.

Types of risk

 

Operational			94
Political			100
Regulatory			103
Financial			104
Environmental			109
Legal and other			111
Industry			112

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:

 

 

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There is no assurance that any of the above risks will not result in:

 

 

Any of these events could result in one or more of our operations becoming unprofitable, cause us not to receive an adequate return on invested capital, or have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

Insurance coverage

We buy insurance to cover losses or liabilities arising from some of the operating risks and hazards listed above. We believe we have a reasonable amount of coverage for the risks we choose to insure against. There is no assurance, however, that this coverage will be adequate in all circumstances, that it will continue to be available, that premiums will be economically feasible, or that we will maintain this coverage. Like other nuclear energy and mining companies, we do not have insurance coverage for certain environmental losses or liabilities and other risks, either because it is not available, or because it cannot be purchased at a reasonable cost. We may also be required to increase the amount of our insurance coverage due to changes in the regulation of the nuclear industry.

Not having the right insurance coverage or the right amount of coverage, or having to increase the amount of coverage or choosing not to insure against certain risks, could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

Flooding at our Saskatchewan mines

All of our operating mines in Saskatchewan have had water inflows.

McArthur River

The sandstone that overlays the basement rocks of the McArthur River deposit contains large volumes of water at significant pressure. Ground freezing at McArthur River generally prevents water from flowing into the area being mined and reduces, but does not eliminate the risk of water inflows. There are technical challenges with the groundwater and rock properties.

We temporarily suspended production at our McArthur River mine in April 2003 because increased water inflow from an area of collapsed rock in a new development area began to flood portions of the mine. This caused a major setback in the development of new mining zones.

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 38 for details).

These water inflows have caused:

 

•

a significant delay in development and production at the property

 

•

a significant increase in capital costs

 

•

the need to notify many of our customers of the interruption in planned uranium supply.

Rabbit Lake

We temporarily reduced our underground activities at Rabbit Lake in November 2007, because there was an increase in water flow from a mining area while an equipment upgrade was limiting surface water-handling system capacity. Rabbit Lake resumed normal mining operations in late December 2007, after the source of the water inflow was plugged.

 

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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 Cigar Lake and McArthur River pose many technical challenges, including groundwater management, unstable rock properties, radiation protection, mining method uncertainty at Cigar Lake, ore-handling and transport and other mining-related challenges.

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

There is a risk to our plan to achieve the full production rate of 18 million pounds per year by 2018 if AREVA is unable to complete and commission the required mill upgrades and expansion on schedule.

The areas being mined at Cigar Lake must meet specific ground freezing requirements before we begin jet boring. We have identified greater variation of the freeze rates of different geological formations encountered in the mine, based on information obtained through surface freeze drilling.

If we are unable to resolve any of these technical challenges, it could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

Reliance on development and expansion projects to fuel growth

Our ability to increase our uranium production depends in part on successfully developing new mines and/or expanding existing operations. Cigar Lake and the McArthur River expansion are our major projects for increasing production.

Several factors affect the economics and success of these projects:

 

 

Generally development projects have no operating history that can be used to estimate future cash flows. We have to invest a substantial amount of capital and time to develop a project and achieve commercial production. A change in costs or construction schedule can affect the economics of a project. Actual costs could increase significantly and economic returns could be materially different from our estimates. We could fail to obtain the necessary governmental approvals for construction or operation. In any of these situations, a project might not proceed according to its original timing, or at all.

 

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It is not unusual in the nuclear energy or mining industries for new or expanded operations to experience unexpected problems during start-up or ramp-up, resulting in delays, higher capital expenditures than anticipated and reductions in planned production. Delays, additional costs or reduced production could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

There is no assurance we will be able to complete the development of new mines, or expand existing operations, economically or on a timely basis.

Developing additional reserves to sustain operations

The McArthur River, Rabbit Lake and Inkai mines are currently our main sources of mined uranium concentrates. Without an expansion of the tailings management facility, production at Rabbit Lake is expected to cease in 2018.

As the reserves at these mines are depleted, our mineral reserves will decrease. We may not be able to sustain production if:

 

•

Cigar Lake does not achieve its planned level of production

 

•

the McArthur River expansion is not successful

 

•

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

 

•

the 2012 MOA setting out a framework to increase Inkai’s annual production from blocks 1 and 2 to 10.4 million pounds (our share 5.2 million pounds) cannot be implemented

 

•

production from our US ISR sites is not sustained or increased

 

•

we do not proceed with, are delayed or do not receive approval for expanding our tailings capacity at Rabbit Lake

 

•

we do not identify, discover or acquire other deposits

 

•

we do not find extensions to existing orebodies, or

 

•

we do not convert resources to reserves at our mines and other projects.

This could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

Although we have successfully replenished reserves in the past through ongoing exploration, development and acquisition programs, there is no assurance that we will be successful in our current or future exploration, development or acquisition efforts. While we believe that Cigar Lake will achieve its planned levels of production there is no assurance it will.

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. We received approval from the CNSC in 2014 to increase tailings capacity and now expect to have enough tailings capacity to mill a volume equal to all the known mineral reserves from McArthur River and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

Rabbit Lake

The Rabbit Lake in-pit tailings management facility has the capacity to store tailings from milling ore from Rabbit Lake until approximately 2018. We are continuing to evaluate options to expand the existing tailings management facility to support mining of existing reserves at Rabbit Lake, and provide additional tailings capacity to process ore from other potential sources.

If sloughing or other issues prevent us from maintaining the existing tailings management capacity at the Deilmann TMF and Rabbit Lake pit, or if we do not proceed with, are delayed or do not receive regulatory approval for new or expanded tailings facilities at Rabbit Lake, 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.

 

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Aging facilities

Our Rabbit Lake mill is aging. 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.

These risks could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

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. An accident or other significant event at a nuclear plant could result in increased regulation, less public support for nuclear energy, lower demand for uranium and lower uranium prices. This could have a material and adverse effect on our own earnings, cash flows, financial condition, results of operations or prospects.

Public acceptance of nuclear energy is uncertain

Maintaining the demand for uranium at current levels and achieving any growth in demand in the future will depend on society’s acceptance of nuclear technology as a means of generating electricity.

On March 11, 2011, a significant earthquake struck the northeast coast of Japan, producing a tsunami and causing massive damage and destruction along the Pacific coastline of Japan. This included damage to the Fukushima-Daiichi nuclear power plant, located in the town of Okuma, about 210 kilometres north of Tokyo. The plant suffered a series of power and equipment failures affecting the cooling water systems and released radioactive material into the environment. The incident at the Fukushima-Daiichi nuclear power plant has called into question public confidence in nuclear energy in Japan and elsewhere around the world. This had an immediate and sustained negative impact on uranium prices and the share price of companies involved in the uranium industry.

Prior to the events of March 11, 2011, Japan had 54 nuclear reactors, which represented 12% of global nuclear generating capacity. As of February 27, 2015, Japan had zero reactors operating. Before any of the reactors can be restarted, they must demonstrate an ability to meet new safety standards that were developed by Japan’s newly established Nuclear Regulatory Authority (NRA).

Germany has decided to revert to its previous phase 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.

Labour and employment

People are core to our business. We compete with other nuclear energy and mining companies for talented, quality people, and we may not always be able to fill positions on a timely basis. There is a limited pool of skilled people and competition is intense. We also experience employee turnover because of an aging workforce.

If we cannot attract and train qualified successors for our senior and operating positions, it could reduce the efficiency of our operations and have an adverse effect on our earnings, cash flows, financial condition or results of operations.

 

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We have unionized employees and face the risk of strikes. At December 31, 2014, we had 3,963 employees (including employees of our subsidiaries). This includes 874 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.

Collective agreements

 

•

The collective agreement with the bargaining unit employees at the McArthur River and Key Lake operations expires December 31, 2017.

 

•

The collective agreement with the bargaining unit employees at our conversion facilities at Port Hope expires June 2016.

 

•

The collective agreement with the bargaining unit employees at CFM expires June 2015.

We cannot predict whether we 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 and GLE through joint ventures with third parties. Some of these joint ventures are unincorporated and some are incorporated (like Inkai and GLE). We have other joint ventures and may enter into more in the future.

There are risks associated with joint ventures, including:

 

•

disagreement with a joint venture partner about how to develop, operate or finance a project

 

•

a joint venture partner not complying with a joint venture agreement

 

•

possible litigation between joint venture partners about joint venture matters

 

•

the inability to exert control over decisions related to a joint venture we do not have a controlling interest in.

Our joint venture partner in Kazakhstan is a state entity, so its actions and priorities could be dictated by government policies instead of commercial considerations.

These risks could result in legal liability, affect our ability to develop or operate a project under a joint venture, or have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

Supplies and contractors

Supplies

We buy reagents and other production inputs and supplies from suppliers around the world. If there is a shortage of any of these supplies, including parts and equipment, or their costs rise significantly, it could limit or interrupt production or increase production costs. It could also have an adverse effect on our ability to carry out operations or have a material and adverse effect on our earnings, cash flows, financial condition or results of operations. We examine our entire supply chain as necessary to identify areas to diversify or add inventory where we may be vulnerable, but there is no assurance that we will be able to mitigate the risk.

Contractors

In some cases we rely on a single contractor to provide us with reagents or other production inputs and supplies. Relying on a single contractor is a security supply risk because we may not receive quality service, timely service, or service that otherwise meets our needs. These risks could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

 

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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.

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. 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:

 

 

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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, results of operations or prospects 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 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 2011, the Kazakhstan government passed a resolution that classified 361 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 which went into effect in 2010 and was amended in 2014 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 nationalize 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

 

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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.

Block 3 Exploration Licence Expiry

The block 3 exploration area at the Inkai mine is governed by an exploration licence granted by the Kazakhstan government. Amendment No. 3 to Inkai’s resource use contract amended Inkai’s block 3 licence, granting a five-year appraisal period to July 2015 to carry out delineation drilling, uranium resource estimation, construction and operation of a test leach facility, and to complete a feasibility study. In 2015, under the terms of the licence, Inkai plans to complete construction of the test leach facility and continue working on a final appraisal of block 3’s mineral potential according to Kazakhstan standards. However, there is no assurance that the test leach facility, the uranium resource estimate and feasibility study will be completed by July 2015.

We are currently working to extend the term of the block 3 exploration licence. Although the Kazakhstan government has extended the term of the licence in the past, there is no assurance that a further extension will be granted or what the terms and conditions of such an extension would be. If an extension is not granted beyond July 2015, the licence for block 3 may expire. This may result in the loss of block 3 without compensation for the loss of Inkai’s investment.

In addition, as of December 31, 2014, Cameco (through a subsidiary) has advanced loans in the principal amount of $136 million (US) to fund Inkai’s work on block 3. If an extension of the exploration licence is not granted or if the block 3 deposit cannot be successfully developed, there is a risk we may not be repaid.

See pages 50 to 52 for a more detailed discussion of the regulatory and political environment in Kazakhstan.

Australia

Western Australian Government’s uranium policy

State governments in Australia have prohibited uranium mining or uranium exploration from time to time, and from 2002 to 2008, uranium mining was banned in Western Australia, where our Kintyre and Yeelirrie projects are located. A prohibition or restriction on uranium exploration or mining in the future that interferes with the development of Kintyre or Yeelirrie could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

State Agreement with Western Australian Government

The Yeelirrie project is governed by a State Agreement with the Western Australian Government. State Agreements are entered into in respect of major Western Australian mining projects, and provide a framework to facilitate approval and development of those projects. It is a requirement under the Yeelirrie State Agreement that we submit to the Government for approval detailed proposals for the development of a uranium mining project and associated infrastructure in respect of Yeelirrie by no later than June 20, 2018.

There is a risk that, if market conditions are such that the development of the Yeelirrie project would not be economically feasible at that time, we will be unable to submit the required development proposals under the State Agreement by June 30, 2018.

If we do require an extension of the deadline to submit the proposals under the State Agreement, we may make such a request of the Western Australian Government between April 1, 2018 and May 31, 2018. Although a number of extensions of the deadline for submitting proposals under the State Agreement have been granted by the government previously, there is no assurance that further extensions will be granted.

If an extension of the deadline is not granted and we do not submit the development proposals by the deadline of June 30, 2018, then the required approvals under the State Agreement are unlikely to be obtained. Without such approvals, the State Agreement will terminate and cease, and the Yeelirrie project tenements and titles granted under the State Agreement will expire. This may result in the loss of the Yeelirrie project without compensation for the loss of the investment.

 

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3 – Regulatory risks

Government laws and regulation

Our business activities are subject to extensive and complex laws and regulations.

There are laws and regulations for uranium exploration, development, mining, milling, refining, conversion, fuel manufacturing, transport, exports, imports, taxes and royalties, labour standards, occupational health, waste disposal, protection and remediation of the environment, decommissioning and reclamation, safety, hazardous substances, emergency response, land use, water use and other matters.

Significant financial and management resources are required to comply with these laws and regulations, and this will likely continue as laws and government regulations become more and more strict. We are unable to predict the ultimate cost of compliance or its effect on our business because legal requirements change frequently, are subject to interpretation and may be enforced to varying degrees.

Some of our operations are regulated by government agencies that exercise discretionary powers conferred by statute. If these agencies do not apply their discretionary authority consistently, then we may not be able to predict the ultimate cost of complying with these requirements or their effect on operations.

Existing, new or changing laws, regulations and standards of regulatory enforcement could increase costs, lower, delay or interrupt production or affect decisions about whether to continue with existing operations or development projects. This could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

If we do not comply with the laws and regulations that apply to our business, or it is alleged we do not comply then regulatory or judicial authorities could take any number of enforcement actions, including:

 

•

corrective measures that require us to increase capital or operating expenditures or install additional equipment

 

•

remedial actions that result in temporary or permanent shut-down or reduction of our operations

 

•

requirements that we compensate communities that suffer loss or damage because of our activities

 

•

civil or criminal fines or penalties.

Legal and political circumstances are different outside North America, which can change the nature of regulatory risks in foreign jurisdictions when compared with regulatory risks associated with operations in North America.

Permitting and licensing

All mining projects and processing facilities around the world require government approvals, licences or permits, and our operations and development projects in Canada, the US, Kazakhstan and Australia are no exception. Depending on the location of the project, this can be a complex and time consuming process involving multiple government agencies.

We have to obtain and maintain many approvals, licences and permits from the appropriate regulatory authorities, but there is no assurance that they will grant or renew them, approve any additional licences or permits for potential changes to our operations in the future or in response to new legislation, or that they will process any of the applications on a timely basis. Stakeholders, like environmental groups, non-government organizations (NGOs) and aboriginal groups claiming rights to traditional lands, can raise legal challenges. A significant delay in obtaining or renewing the necessary approvals, licences or permits, or failure to receive the necessary approvals, licences or permits, could interrupt our operations or prevent them from operating, which could have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

 

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4 – Financial risks

Volatility and sensitivity to prices

Since a significant portion of our revenues come from the sale of uranium and conversion services, our earnings and cash flow are closely related to, and sensitive to, fluctuations in the long and short-term market prices of U₃O₈ and uranium conversion services.

Many factors beyond our control affect these prices, including the following, among others:

 

•

demand for nuclear power

 

•

forward contracts of U3O8 supplies for nuclear power plants

 

•

political and economic conditions in countries producing and buying uranium

 

•

reprocessing of used reactor fuel and the re-enrichment of depleted uranium tails

 

•

sales of excess civilian and military inventories of uranium by governments and industry participants

 

•

levels of uranium production and production costs

 

•

significant interruptions in production or delays in expansion plans or new mines going into production

 

•

investment and hedge fund activity in the uranium market.

We cannot predict the effect that any one or all of these factors will have on the price of U₃O₈ and uranium conversion services. Prices have fluctuated widely in the last several years, and there have been significant declines in U₃O₈ prices since 2011.

 

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

 

Range of spot uranium prices US$/lb of U3O8
		2010				2011				2012				2013				2014
High		$	62.25			$	72.63			$	52.13			$	43.88			$	39.50
Low			40.75				49.13				41.75				34.50				28.23
Spot UF6 conversion values US$/kg U
High		$	13.00			$	13.00			$	10.50			$	10.50			$	8.25
Low			5.38				8.00				6.63				8.50				7.25
The next table shows the range in term prices over the last five years.
Range of term uranium prices US$/lb of U3O8
		2010				2011				2012				2013				2014
High		$	66.00			$	71.50			$	61.25			$	57.00			$	50.00
Low			59.00				62.00				56.50				50.00				44.00
Term UF6 conversion values US$/kg U
High		$	15.00			$	16.75			$	16.75			$	16.75			$	16.00
Low			11.00				15.25				16.75				16.00				16.00

Notes

Spot and term uranium prices are the average of prices published monthly by Ux Consulting and from The Nuexco Exchange Value, published by TradeTech.

Spot and term UF₆ conversion values are the average of the North American prices published monthly by Ux Consulting and from The Nuexco Conversion Value, published by TradeTech.

If prices for U₃O₈ or uranium conversion services fall below our own production costs for a sustained period, continued production or conversion at our sites may cease to be profitable. This would have a material and adverse effect on our earnings, cash flows, financial condition, results of operations or prospects.

Declines in U₃O₈ prices could also delay or deter a decision to build or begin commercial production at one or more of our development projects, or adversely affect our ability to finance these development projects. Either of these could have an adverse effect on our future earnings, cash flows, financial condition, results of operations or prospects.

A sustained decline in U₃O₈ prices may require us to write down our mineral reserves and mineral resources, and any significant write downs may lead to material write downs of our investment in the mining properties affected, and an increase in charges for amortization, reclamation and closures.

In our uranium segment, we use a uranium marketing strategy as a way to reduce volatility in our future earnings and cash flow from exposure to fluctuations in uranium prices. It involves building a portfolio that consists of fixed-price contracts and market-related contracts with terms of 5 to 10 years (on average). This strategy can create opportunity losses because we may not benefit fully if there is a significant increase in U₃O₈ prices. This strategy also creates currency risk since we receive payment under the majority of our sales contracts in US$. There is no assurance that our contracting strategy will be successful.

Through our uranium segment and NUKEM, we participate in the uranium spot market from time to time, making purchases so we can put material into higher priced contracts. There are, however, risks associated with spot market purchases, including the risk of losses, which could have an adverse effect on our earnings, cash flows, financial condition or results of operations.

 

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Reserve, resource, production and capital cost estimates

Reserve and resource estimates are not precise

Our mineral reserves and resources are the foundation of our uranium mining operations. They dictate how much uranium concentrate we can produce, and for how many years.

The uranium mineral reserves and resources reported in this AIF are estimates, and are therefore subjective. There is no assurance that the indicated tonnages or grades of uranium will be mined or milled or that we will receive the uranium price we used in estimating these reserves.

While we believe that the mineral reserve and resource estimates included in this AIF are well established and reflect management’s best estimates, reserve and resource estimates, by their nature, are imprecise, do not reflect exact quantities and depend to a certain extent on statistical inferences that may ultimately prove unreliable. The volume and grade of reserves we actually recover, and rates of production from our current mineral reserves, may be less than the estimate of the reserves. Fluctuations in the market price of uranium, changing exchange rates and operating and capital costs can make reserves uneconomic to mine in the future and ultimately cause us to reduce our reserves.

Short-term operating factors relating to mineral reserves, like the need for orderly development of orebodies or the processing of different ore grades, can also prompt us to modify reserve estimates or make reserves uneconomic to mine in the future, and can ultimately cause us to reduce our reserves. Reserves also may have to be re-estimated based on actual production experience.

Mineral resources may ultimately be reclassified as proven or probable mineral reserves if they demonstrate profitable recovery. Estimating reserves or resources is always affected by economic and technological factors, which can change over time, and experience in using a particular mining method. There is no assurance that any resource estimate will ultimately be reclassified as proven or probable reserves. If we do not obtain or maintain the necessary permits or government approvals, or there are changes to applicable legislation, it could cause us to reduce our reserves.

Mineral resource and reserve estimates can be uncertain because they are based on data from limited sampling and drilling and not from the entire orebody. As we gain more knowledge and understanding of an orebody, the resource and reserve estimate may change significantly, either positively or negatively.

If our mineral reserve or resource estimates for our uranium properties are inaccurate or are reduced in the future, it could:

 

•

require us to write down the value of a property

 

•

result in lower uranium concentrate production than previously estimated

 

•

require us to incur increased capital or operating costs, or

 

•

require us to operate mines or facilities unprofitably.

This could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations or prospects.

Production and capital cost estimates may be inaccurate

We prepare estimates of future production and capital costs for particular operations, but there is no assurance we will achieve these estimates. Estimates of expected future production and capital costs are inherently uncertain, particularly beyond one year, and could change materially over time.

Production and capital cost estimates for:

 

•

McArthur River assume that development, mining and production plans proceed as expected

 

•

Cigar Lake assume that development, mining and production plans proceed as expected

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:

 

 

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 exchange rates.

Customers

Our main business relates to the production and sale of uranium concentrates (our uranium segment) and providing uranium conversion services (our fuel services segment). We rely heavily on a small number of customers to purchase a significant portion of our uranium concentrates and conversion services.

From 2015 through 2017, we expect:

 

•

in our uranium segment, our five largest customers to account for 48% of our contracted supply of U3O8

 

•

in our fuel services segment, our five largest UF6 conversion customers to account for 52% of our contracted supply of UF6 conversion services.

We are a supplier of UO₂ used by Canadian CANDU heavy water reactors. Our sales to our largest customer accounted for 40% of our UO₂ sales in 2014.

 

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In addition, revenues in 2014 from one customer of our uranium and conversion segments represented $213 million (9.9%) of our total revenues from those businesses. Sales for the Bruce A and B reactors represent a substantial portion of our fuel manufacturing business.

If we lose any of our largest customers or if any of them curtails their purchases, it could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

Counterparty and credit risk

Our business operations expose us to the risk of counterparties not meeting their contractual obligations, including:

 

•

customers

 

•

suppliers

 

•

financial institutions and other counterparties to our derivative financial instruments and hedging arrangements relating to foreign currency exchange rates and interest rates

 

•

financial institutions which hold our cash on deposit

 

•

insurance providers.

Credit risk is the risk that counterparties will not be able to pay for services provided under the terms of the contract. If a counterparty to any of our significant contracts defaults on a payment or other obligation or becomes insolvent, it could have a material and adverse effect on our cash flows, earnings, financial condition or results of operations.

Uranium products, conversion and fuel services

In our uranium and fuel services segments, we manage the credit risk of our customers for uranium products, conversion and fuel services by:

 

•

monitoring their creditworthiness

 

•

asking for pre-payment or another form of security if they pose an unacceptable level of credit risk.

As of December 31, 2014, 93% of our forecast revenue under contract for the period 2015 to 2017 is with customers whose creditworthiness meets our standards for unsecured payment terms.

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 planned for 2015. 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.

 

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Operating and capital plans

We establish our operating and capital plans based on the information we have at the time, including expert opinions. There is no assurance, however, that these plans will not change as new information becomes available or there is a change in expert opinion.

Pre-feasibility and feasibility studies contain estimated capital and operating costs, production and economic returns and other estimates that may be significantly different than actual results, and there is no assurance that they will not be different than anticipated or than what was disclosed in the studies. Our estimates may also be different from those of other companies, so they should not be used to project operating profit.

Internal controls

We use internal controls over financial reporting to provide reasonable assurance that we authorize transactions, safeguard assets against improper or unauthorized use, and record and report transactions properly. This gives us reasonable assurance that our financial reporting is reliable, and prepared in accordance with IFRS.

It is impossible for any system to provide absolute assurance or guarantee reliability, regardless of how well it is designed or operated. We continue to evaluate our internal controls to identify areas for improvement and provide as much assurance as reasonably possible. We conduct an annual assessment of our internal controls over financial reporting and produce an attestation report of their effectiveness by our independent auditors to meet the requirement of Section 404 of the Sarbanes-Oxley Act of 2002.

If we do not satisfy the requirements for internal controls on an ongoing, timely basis, it could negatively affect investor confidence in our financial reporting, which could have an impact on our business and the trading price of our common shares. If a deficiency is identified and we do not introduce new or better controls, or have difficulty implementing them, it could harm our financial results or our ability to meet reporting obligations.

Carrying values of assets

We evaluate the carrying value of our assets to decide whether current events and circumstances indicate whether or not we can recover the carrying amount. This involves comparing the estimated fair value of our reporting units to their carrying values.

We base our fair value estimates on various assumptions, however, the actual fair values can be significantly different than the estimates. If we do not have any mitigating valuation factors or experience a decline in the fair value of our reporting units, it could ultimately result in an impairment charge.

5 – Environmental risks

Complex legislation and environmental, health and safety risk

Our activities have an impact on the environment, so our operations are subject to extensive and complex laws and regulations relating to the protection of the environment, employee health and safety and waste management. We also face risks that are unique to uranium mining, processing and fuel manufacturing. Laws to protect the environment as well as employee health and safety are becoming more stringent for members of the nuclear energy industry.

Our facilities operate under various operating and environmental approvals, licences and permits that have conditions that we must meet as part of our regular business activities. In a number of instances, our right to continue operating these facilities depends on our compliance with these conditions.

Our ability to obtain approvals, licences and permits, maintain them, and successfully develop and operate our facilities may be adversely affected by the real or perceived impact of our activities on the environment and human health and safety at our development projects and operations and in the surrounding communities. The real or

 

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perceived impact of activities of other nuclear energy or mining companies can also have an adverse effect on our ability to secure and maintain approvals, licences and permits.

Our compliance with laws and regulations relating to the protection of the environment, employee health and safety, and waste management requires significant expenditures and can cause delays in production or project development. This has been the case in the past and may be so in the future. Failing to comply can lead to fines and penalties, temporary or permanent suspension of development and operational activities, clean-up costs, damages and the loss of, or the inability to obtain, key approvals, permits and licences. We are exposed to these potential liabilities for our current development projects and operations as well as operations that have been closed. There is no assurance that we have been or will be in full compliance with all of these laws and regulations, or with all the necessary approvals, permits and licences.

Laws and regulations on the environment, employee health and safety, and waste management continue to evolve and this can create significant uncertainty around the environmental, employee health and safety, and waste management costs we incur. If new legislation and regulations are introduced in the future, they could lead to additional capital and operating costs, restrictions and delays at existing operations or development projects, and the extent of any of these possible changes cannot be predicted in a meaningful way.

Environmental and regulatory review is a long and complex process that can delay the opening, modification or expansion of a mine, conversion facility or refining facility, or extend decommissioning activities at a closed mine or other facility.

Our ability to foster and maintain the support of local communities and governments for our development projects and operations is critical to the conduct and growth of our business, and we do this by engaging in dialogue and consulting with them about our activities and the social and economic benefits they will generate. There is no assurance, however, that this support can be fostered or maintained. There is an increasing level of public concern relating to the perceived effect that nuclear energy and mining activities have on the environment and communities affected by the activities. Some NGOs are vocal critics of the nuclear energy and mining industries, and oppose globalization, nuclear energy and resource development. Adverse publicity generated by these NGOs or others, related to the nuclear energy industry or the extractive industry in general, or our operations in particular, could have an adverse effect on our reputation or financial condition and may affect our relationship with the communities we operate in. While we are committed to operating in a socially responsible way, there is no guarantee that our efforts will mitigate this 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 conceptual decommissioning plans for some of our properties with the regulators. We review these plans for Canadian facilities every five years, or at the time of an amendment or renewal of an operating licence. Plans for our US sites are reviewed every year. Regulators review our conceptual plans on a regular basis. As the sites approach or go into decommissioning, regulators review the detailed decommissioning plans, and this can lead to additional requirements, costs and financial assurances. It is not possible to predict what level of decommissioning and reclamation and financial assurances regulators may require in the future.

If we must comply with additional regulations, or the actual cost of decommissioning and reclamation in the future is significantly higher than our current estimates, this could have a material and adverse effect on our future earnings, cash flows, financial condition or results of operations.

 

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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.

6 – Legal and other risks

Litigation

We are currently subject to litigation or threats of litigation, and may be involved in disputes with other parties in the future that result in litigation. This litigation may involve joint venture partners, suppliers, governments, regulators, tax authorities or other persons.

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, results of operations or prospects. See Legal proceedings on page 113 for more information.

We are also currently involved in tax litigation with CRA and have received a RAR from the IRS. See Transfer pricing disputes at pages 88 to 91. In addition, we are subject to the risk that CRA or the IRS may challenge or seek to reassess our income tax returns on a similar basis for other previously reported periods, and the risk that CRA, the IRS or other tax authorities in other countries may seek to challenge or reassess our income tax returns on a different basis for the same periods or other previously reported periods. Substantial success for CRA would be material, and other unfavourable outcomes of challenges or reassessments initiated by the IRS or the tax authorities in other countries could be material to our cash flows, financial condition, results of operations or prospects.

Legal rights

If a dispute arises at our foreign operations, it may be under the exclusive jurisdiction of foreign courts, or we may not be successful in subjecting foreign persons to the jurisdiction of courts in Canada. We could also be hindered or prevented from enforcing our rights relating to a government entity or instrumentality because of the doctrine of sovereign immunity.

The dispute resolution provision of the resource use contract for Inkai stipulates that any dispute between the parties is to be submitted to international arbitration. There is no assurance, however, that a particular government entity or instrumentality will either comply with the provisions of this or any other agreements, or voluntarily submit a dispute to arbitration. If we are unable to enforce our rights under these agreements, this could have a material and adverse effect on our earnings, cash flows, financial condition or results of operations.

Defects in title

We have investigated our rights to explore and exploit all of our material properties, and those rights are in good standing to the best of our knowledge. There is no assurance, however, that these rights will not be revoked or significantly altered to our detriment, or that our rights will not be challenged by third parties, including local governments and by indigenous groups, such as First Nations and Métis in Canada.

Indigenous rights, title claims and consultation

Managing indigenous rights, title claims and consultation is an integral part of our exploration, development and mining activities, and we are committed to managing them effectively. Cameco has signed agreements, or is in negotiations, with the communities closest to our operations to help mitigate the risks associated with potential First Nations and Métis land or consultation claims that could impact our operations. These agreements provide substantial socioeconomic opportunities to these communities and also provide us with support for our operations from those communities. There is no assurance, however, that we will not face material adverse consequences because of the legal and factual uncertainties inherent with indigenous rights, title claims and consultation.

 

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Saskatchewan

Exploration, development, mining, milling and decommissioning activities at our various properties in Saskatchewan may be affected by claims by the First Nations and Métis, and related consultation issues.

We also face similar issues with our exploration activities in other provinces and countries.

It is generally acknowledged that under historical treaties, First Nations in northern Saskatchewan ceded title to most traditional lands in the region in exchange for treaty benefits and reserve lands. Some First Nations in Saskatchewan, however, 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.

Fuel fabrication defects and product liability

We fabricate nuclear fuel bundles, other reactor components and monitoring equipment. These products are complex and may have defects that can be detected at any point in their product life cycle. Flaws in the products could materially and adversely affect our reputation, which could result in a significant cost to us and have a negative effect on our ability to sell our products in the future. We could also incur substantial costs to correct any product errors, which could have an adverse effect on our operating margins. While we introduced a new rigorous process for review and control in 2007, there is no guarantee that we will detect all defects or errors in our products.

It is possible that some customers may demand compensation if we deliver defective products. If there are a significant number of product defects, it could have a significant impact on our operating results.

Agreements with some customers may include specific terms limiting our liability to customers. Even if there are limited liability provisions in place, existing or future laws, or unfavourable judicial decisions may make them ineffective. We have not experienced any material product liability claims to date, however, they could occur in the future because of the nature of nuclear fuel products. A successful product liability claim could result in significant monetary liability and could seriously disrupt our fuel manufacturing business and the company overall.

7 – Industry risks

Alternate sources of energy

Nuclear energy competes with other sources of energy like oil, natural gas, coal and hydro-electricity. These sources are somewhat interchangeable with nuclear energy, particularly over the longer term.

If lower prices of oil, natural gas, coal and hydro-electricity are sustained over time, it may result in lower demand for uranium concentrates and uranium conversion services, which could lead to lower uranium prices. Growth of the uranium and nuclear power industry will depend on continuing and growing acceptance of nuclear technology to generate electricity. Unique political, technological and environmental factors affect the nuclear industry, exposing it to the risk of public opinion, which could have a negative effect on the demand for nuclear power and increase the regulation of the nuclear power industry. An accident at a nuclear reactor anywhere in the world could affect the acceptance of nuclear energy and the future prospects for nuclear generation, which could have a material and adverse effect on our future earnings, cash flows, financial condition, results of operations or prospects.

Industry competition and international trade restrictions

The international uranium industry, which includes supplying uranium concentrates and providing uranium conversion services, is highly competitive. We market uranium to utilities, and directly compete with a relatively small number of uranium mining and enrichment companies in the world. Their supply may come from mining uranium, excess inventories, including inventories made available from decommissioning of nuclear weapons, reprocessed uranium and plutonium derived from used reactor fuel, and from using excess enrichment capacity to re-enrich depleted uranium tails.

 

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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. 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, particularly in the US, Japan and Europe, could affect the market for nuclear and other fuels and could lead to the premature shutdown of some nuclear reactors.

Deregulation has resulted in utilities improving the performance of their reactors to record capacity, but there is no assurance this trend will continue.

Deregulation can have a material and adverse effect on our future earnings, cash flows, financial condition or results of operations.

Legal proceedings

We discuss any legal proceedings that we or our subsidiaries are a party to in note 22 to the 2014 financial statements.

 

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Investor information

Share capital

Our authorized share capital consists of:

 

•

first preferred shares

 

•

second preferred shares

 

•

common shares

 

•

one class B share.

Preferred shares

We do not currently have any preferred shares outstanding, but we can issue an unlimited number of first preferred or second preferred shares with no nominal or par value, in one or more series. The board must approve the number of shares, and the designation, rights, privileges, restrictions and conditions attached to each series of first or second preferred shares.

Preferred shares can carry voting rights, and they rank ahead of common shares and the class B share for receiving dividends and distributing assets if the company is liquidated, dissolved or wound up.

First preferred shares

Each series of first preferred shares ranks equally with the shares of other series of first preferred shares. First preferred shares rank ahead of second preferred shares, common shares and the class B share.

Second preferred shares

Each series of second preferred shares ranks equally with the shares of other series of second preferred shares. Second preferred shares rank after first preferred shares and ahead of common shares and the class B share.

Common shares

We can issue an unlimited number of common shares with no nominal or par value. Only holders of common shares have full voting rights in Cameco.

If you hold our common shares, you are entitled to vote on all matters that are to be voted on at any shareholder meeting, other than meetings that are only for holders of another class or series of shares. Each Cameco share you own represents one vote, except where noted below. As a holder of common shares, you are also entitled to receive any dividends that are declared by our board of directors.

Common shares rank after preferred shares with respect to the payment of dividends and the distribution of assets if the company is liquidated, dissolved or wound up, or any other distribution of our assets among our shareholders if we were to wind up our affairs.

Holders of our common shares have no pre-emptive, redemption, purchase or conversion rights for these shares. Except as described under Ownership and voting restrictions, non-residents of Canada who hold common shares have the same rights as shareholders who are residents of Canada.

As at February 5, 2015, we had 395,792,522 common shares outstanding. These were fully paid and non-assessable.

As of February 5, 2015, there were 8,313,451 stock options outstanding to acquire common shares of Cameco under the company’s stock option plan with exercise prices ranging from $19.37 to $54.38.

In 2014, we granted the following stock options:

March 3, 2014 – 765,146 stock options to acquire common shares of Cameco at an exercise price of $26.81.

 

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Our articles of incorporation have provisions that restrict the issue, transfer and ownership of voting securities of Cameco (see Ownership and voting restrictions below).

Class B shares

The province of Saskatchewan holds our one class B share outstanding. It is fully paid and non-assessable.

The one class B share entitles the province to receive notices of and attend all meetings of shareholders, for any class or series.

The class B shareholder can only vote at a meeting of class B shareholders, and only as a class if there is a proposal to:

 

•

amend Part 1 of Schedule B of the articles, which states that:

 

•

Cameco’s registered office and head office operations must be in Saskatchewan

 

•

the vice-chairman of the board, chief executive officer (CEO), president, chief financial officer (CFO) and generally all of the senior officers (vice-presidents and above) must live in Saskatchewan

 

•

all annual meetings of shareholders must be held in Saskatchewan

 

•

amalgamate, if it would require an amendment to Part 1 of Schedule B of the articles, or

 

•

amend the articles in a way that would change the rights of class B shareholders.

The class B shareholder can request and receive information from us to determine whether or not we are complying with Part 1 of Schedule B of the articles.

The class B shareholder does not have the right to receive any dividends declared by Cameco. The class B share ranks after first and second preferred shares, but equally with common shareholders, with respect to the distribution of assets if the company is liquidated, dissolved or wound up. The class B shareholder has no pre-emptive, redemption, purchase or conversion rights with its class B share, and the share cannot be transferred.

Ownership and voting restrictions

The federal government established ownership restrictions when Cameco was formed so we would remain Canadian controlled. There are restrictions on issuing, transferring and owning Cameco common shares whether you own the shares as a registered shareholder, hold them beneficially or control your investment interest in Cameco directly or indirectly. These are described in the Eldorado Nuclear Limited Reorganization and Divestiture Act (Canada) (ENL Reorganization Act) and our company articles.

The following is a summary of the restrictions listed in our company articles.

Residents

A Canadian resident, either individually or together with associates, cannot hold, beneficially own or control shares or other Cameco securities, directly or indirectly, representing more than 25% of the votes that can be cast to elect directors.

Non-residents

A non-resident of Canada, either individually or together with associates, cannot hold, beneficially own or control shares or other Cameco securities, directly or indirectly, representing more than 15% of the total votes that can be cast to elect directors.

Voting restrictions

All votes cast at the meeting by non-residents, either beneficially or controlled directly or indirectly, will be counted and pro-rated collectively to limit the proportion of votes cast by non-residents to no more than 25% of the total shareholder votes cast at the meeting.

There have been instances in prior years, including 2014, when we have limited the counting of votes by non-residents of Canada at our annual meeting of shareholders to abide by this restriction. This has resulted in non-residents receiving less than one vote per share.

 

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Enforcement

The company articles allow us to enforce the ownership and voting restrictions by:

 

•

suspending voting rights

 

•

forfeiting dividends and other distributions

 

•

prohibiting the issue and transfer of Cameco shares

 

•

requiring the sale or disposition of Cameco shares

 

•

suspending all other shareholder rights.

To verify compliance with restrictions on ownership and voting of Cameco shares, we require existing shareholders, proposed transferees or other subscribers for voting shares to declare their residency, ownership of Cameco shares and other things relating to the restrictions. Nominees such as banks, trust companies, securities brokers or other financial institutions who hold the shares on behalf of beneficial shareholders need to make the declaration on their behalf.

We cannot issue or register a transfer of any voting shares if it would result in a contravention of the resident or non-resident ownership restrictions.

If we believe there is a contravention of our ownership restrictions based on any shareholder declarations filed with us, or our books and records or those of our registrar and transfer agent or otherwise, we can suspend all shareholder rights for the securities they hold, other than the right to transfer them. We can only do this after giving the shareholder 30 days’ notice, unless he or she has disposed of the holdings and we have been advised of this.

Understanding the terms

Please see our articles for the exact definitions of associate, resident, non-resident, control, and beneficial ownership which are used for the restrictions described above.

Other restrictions

The ENL Reorganization Act imposes some additional restrictions on Cameco. We must maintain our registered office and our head office operations in Saskatchewan. We are also prohibited from:

 

•

creating restricted shares (these are generally defined as a participating share with restrictive voting rights)

 

•

applying for continuance in another jurisdiction

 

•

enacting articles of incorporation or bylaws that have provisions that are inconsistent with the ENL Reorganization Act.

We must maintain our registered office and head office operations in Saskatchewan under the Saskatchewan Mining Development Corporation Reorganization Act. This generally includes all executive, corporate planning, senior management, administrative and general management functions.

Credit ratings

Credit ratings provide an independent, professional assessment of a corporation’s credit risk. They are not a comment on the market price of a security or suitability for an individual investor and are, therefore, not recommendations to buy, hold or sell our securities.

We provide rating agencies DBRS Limited (DBRS) and Standard & Poor’s (S&P) with confidential, in-depth information to support the credit rating process.

The credit ratings assigned to our securities by external ratings agencies are important to our ability to raise capital at competitive pricing to support our business operations and liquidity position.

The rating agencies may revise or withdraw these ratings if they believe circumstances warrant. A material downgrade in our credit ratings would likely increase our cost of funding significantly and our ability to access funding and capital through the capital markets could be reduced.

 

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We have four series of senior unsecured debentures outstanding:

 

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$500 million of debentures issued on September 2, 2009 that have an interest rate of 5.67% per year and mature September 2, 2019

 

•

$400 million of debentures issued on November 14, 2012 that have an interest rate of 3.75% per year and mature on November 14, 2022

 

•

$100 million of debentures issued on November 14, 2012 that have an interest rate of 5.09% per year and mature on November 14, 2042

 

•

$500 million of debentures issued on June 24, 2014 that have an interest rate of 4.19% per year and mature on June 24, 2024.

We have a commercial paper program which is supported by a $1,250,000 unsecured revolving credit facility that matures November 1, 2018. As of December 31, 2014, there were no amounts outstanding under the commercial paper facility.

The table below shows the current DBRS and S&P ratings and the rating trends/outlooks of our commercial paper and senior unsecured debentures:

 

Rating Agency		Rating		Rating Trend/Outlook
Commercial papers
DBRS		R-1 (low)		Stable
S&P		A-1 (low)		Negative
Senior Unsecured Debentures
DBRS		A (low)		Stable
S&P		BBB+		Negative

DBRS uses rating trends to provide guidance regarding the outlook for the rating assigned. The trend is an indication of the likelihood that the rating could change in the future and the direction in which DBRS considers the rating is headed should present tendencies continue, or in some cases, unless challenges are addressed.

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

The rating agencies may revise or withdraw these ratings if they believe circumstances warrant.

Commercial paper

Rating scales for commercial paper are meant to indicate the risk that a borrower will not fulfill its near-term debt obligations in a timely manner.

The table below explains the credit ratings of our commercial paper in more detail:

 

		Rating		Ranking
DBRS		R-1 (low)		•				lower end of the R-1 category
rates commercial paper by categories ranging from a high of R-1 to a low of D				•				represents “good credit quality”
				•				third highest of 10 available credit ratings
S&P   rates commercial paper by categories ranging from a high of A-1 (high) to a low of D		A-1 (low)		•				represents “satisfactory capacity to meet its financial commitments on the obligation”
				•				third highest of eight available credit ratings

Senior unsecured debentures

Long-term debt rating scales are meant to indicate the risk that a borrower will not fulfill its full obligations, with respect to interest and principal, in a timely manner.

 

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The table below explains the credit ratings of our senior unsecured debentures in more detail:

 

		Rating		Ranking
DBRS		A (low)		•		lower end of the A category
rates senior unsecured debentures by categories ranging from a high of AAA to a low of D				•		represents “good credit quality”
				•		third highest of 10 available credit ratings
				•		capacity for the payment of financial obligations is substantial, but of lesser credit quality than AA
				•		may be vulnerable to future events, but qualifying negative factors are considered manageable
				•		“stable” trend means the rating is not likely to change in the future
S&P		BBB+		•		higher end of the BBB category
rates senior unsecured debentures by categories ranging from a high of AAA to a low of D				•		exhibits “adequate protection parameters”
				•		fourth highest of 10 available credit ratings
				•		adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity to meet financial commitment
				•		“negative” outlook means the rating may be lowered in the future

Payments to Credit Rating Agencies

Over the last two years, we paid $832,184 in connection with the credit ratings disclosed above, of that $477,500 related to new issuance fees for the ratings of the senior unsecured debentures issued in 2014.

Material contracts

We are required by law to describe our material contracts in this AIF (not including material contracts that we entered into as part of the ordinary course of business) that we entered into before 2014 and remain in effect – there are five, which are described below. We did enter into a material contract in 2014 that remains in effect, which is described below.

Supplemental indentures

We entered into the Fourth supplemental indenture with CIBC Mellon Trust Company (CIBC Mellon) on September 2, 2009, relating to the issue of $500 million in unsecured debentures at an interest rate of 5.67% per year and due in 2019.

We entered into the Fifth supplemental indenture with CIBC Mellon on November 14, 2012, relating to the issue of $400 million in unsecured debentures at an interest rate of 3.75% per year and due in 2022.

We entered into the Sixth supplemental indenture with CIBC Mellon on November 14, 2012, relating to the issue of $100 million in unsecured debentures at an interest rate of 5.09% per year and due in 2042.

We entered into the Seventh supplemental indenture with CIBC Mellon on June 24, 2014, relating to the issue of $500 million in unsecured debentures at an interest rate of 4.19% per year and due in 2024.

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

 

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US Trust Indenture

We entered into an indenture with The Bank of New York Mellon on May 22, 2012 to set forth the general terms and provisions of debt securities. The terms of this indenture were fully described in our final short form base shelf prospectus dated December 9, 2014. We have not issued any debt securities under this indenture. The specific terms of any offering of debt securities under this indenture would be set forth in a shelf prospectus supplement.

Market for our securities

Our common shares are listed and traded on the Toronto Stock Exchange (under the symbol CCO) and the New York Stock Exchange (under the symbol CCJ).

We have a registrar and transfer agent in Canada (CST) and the US (American Stock Transfer) for our common shares:

 

Canada		CST Trust Company P.O. Box 700, Station B Montreal, Quebec H3B 3K3		US		American Stock Transfer & Trust Company, LLC 6201 15th Avenue Brooklyn, New York United States of America 11219

Trading activity

The table below shows the high and low closing prices and trading volume for our common shares on the TSX in 2014.

 

2014		High ($)				Low ($)				Volume
January			25.40				21.06				31,982,050
February			27.19				21.83				32,293,269
March			28.57				24.88				27,223,870
April			27.39				22.42				27,707,461
May			23.55				20.65				19,560,835
June			22.02				20.25				16,685,979
July			23.26				20.25				22,528,693
August			22.74				20.75				17,186,090
September			21.88				19.52				18,440,768
October			19.89				17.60				23,778,944
November			22.46				18.43				26,091,638
December			21.30				17.25				31,931,840

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.

 

		2014				2013				2012
Cash dividends		$	0.40			$	0.40			$	0.40

 

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Governance

Directors

 

Director		Board committees		Principal occupation or employment
Ian Bruce Calgary, Alberta, Canada   Director since 2012		Audit and finance Human resources and compensation Reserves oversight		Corporate director as of 2010 2010 to 2011 – Co-Chairman, Peters & Co. Limited 2002 to 2010 – Chief Executive Officer, Peters & Co. Limited
Daniel Camus Geneva, Switzerland   Director since 2011		Audit and finance Human resources and compensation Safety, health and environment		Corporate director as of 2011 2012 to present – Chief Financial Officer of The Global Fund to Fight Aids, Tuberculosis and Malaria 2005 to 2010 – Head of Strategy and International Activities of Electricité de France SA 2002 to 2010 – Group chief financial officer of Electricité de France SA
John Clappison Toronto, Ontario, Canada   Director since 2006		Audit and finance (Chair) Nominating, corporate governance and risk		Corporate director as of 2006
Joe Colvin Santa Fe, New Mexico, USA   Director since 1999		Safety, health and environment (Chair) Human resources and compensation		June 2011 to present – Past-President of American Nuclear Society June 2010 to June 2011 – President of American Nuclear Society February 2005 to present – President emeritus of the Nuclear Energy Institute
James Curtiss Wagener, South Carolina, USA   Director since 1994		Human resources and compensation (Chair) Nominating, corporate governance and risk		April 2008 to present – principal of Curtiss Law
Donald Deranger Prince Albert, Saskatchewan, Canada   Director since 2009		Reserves oversight Safety, health and environment		May 2013 to present – non-executive chair of the board of Points Athabasca Contracting LP 1997 to present – Advisor to the Athabasca Basin Development Corporation 2001 to May 2013 – President of Points Athabasca Contracting LP 2003 to 2012 – Athabasca Vice Chief of the Prince Albert Grand Council
Catherine Gignac Mississauga, Ontario, Canada   Director since 2014		Audit and finance Reserves oversight Safety, health and environment		September 2011 to present – principal of Catherine Gignac & Associates April 2009 to September 2011 – mining equity research analyst with NCP Northland Capital Partners
Tim Gitzel Saskatoon, Saskatchewan, Canada   Director since 2011		None		July 2011 to present – President and CEO May 2010 to June 2011 – President January 2007 to May 2010 – Senior Vice-President and Chief Operating Officer

 

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Director		Board committees		Principal occupation or employment
James Gowans Toronto, Ontario, Canada   Director since 2009		Reserves oversight (Chair) Safety, health and environment		July 2014 to present – Co-President of Barrick Gold Corporation January 2014 to July 2014 – Executive Vice-President and Chief Operating Officer of Barrick Gold Corporation January 2011 to January 2014 – Managing Director, Debswana Diamond Company March 2010 to December 2010 – COO and Chief Technical Officer of DeBeers SA
Nancy Hopkins Saskatoon, Saskatchewan, Canada   Director since 1992		Nominating, corporate governance and risk (Chair) Audit and finance		1984 to present – Lawyer, partner, McDougall Gauley LLP
Anne McLellan Edmonton, Alberta, Canada   Director since 2006		Human resources and compensation Nominating, corporate governance and risk Safety, health and environment		July 2006 to present – Senior Advisor at Bennett Jones LLP July 2006 to June 2013 – Distinguished Scholar in Residence at Alberta Institute for American Studies, University of Alberta
Neil McMillan Saskatoon, Saskatchewan, Canada   Director since 2002		Chair		Corporate director as of April 2014 2004 to March 2014 – President and Chief Executive Officer, Claude Resources Inc.
Victor Zaleschuk Calgary, Alberta, Canada   Director since 2001		Human resources and compensation Nominating, corporate governance and risk Reserves oversight		2001 to present – Corporate director

All of the directors are elected for a term of one year, and hold office until the next annual meeting unless he or she steps down, as required by corporate law.

Officers

 

Officer		Principal occupation or employment for past five years
Neil McMillan Chair of the Board Saskatoon, Saskatchewan, Canada		Corporate director as of April 2014 2004 to March 2014 – President and Chief Executive Officer, Claude Resources Inc.
Tim Gitzel President and Chief Executive Officer Saskatoon, Saskatchewan, Canada		Assumed current position July 2011 May 2010 to June 2011 – President January 2007 to May 2010 – Senior Vice-President and Chief Operating Officer
Sean Quinn Senior Vice-President, Chief Legal Officer and Corporate Secretary Saskatoon, Saskatchewan, Canada		Assumed current position April 2014 May 2004 to March 2014 – Vice-President, Law and General Counsel

 

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Officer		Principal occupation or employment for past five years
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
Ken Seitz Senior Vice-President and Chief Commercial Officer Saskatoon, Saskatchewan, Canada		Assumed current position January 2011 2009 to December 2010 – Vice-President, Marketing Strategy and Administration 2006 to 2009 – Vice-President, Corporate Development and Power Generation
Robert Steane Senior Vice-President and Chief Operating Officer Saskatoon, Saskatchewan, Canada		Assumed current position May 2010 2007 to May 2010 – Vice-President, Major Projects
Alice Wong Senior Vice-President and Chief Corporate Officer Saskatoon, Saskatchewan, Canada		Assumed current position July 2011 October 2008 to July 2011 – Vice-President, Safety, Health, Environment, Quality and Regulatory Relations

To our knowledge, the total number of common shares that the directors and executive officers as a group either: (i) beneficially owned; or (ii) exercised direction or control over, directly or indirectly, was 362,830 as at February 27, 2015. This represents less than 1% of our outstanding common shares.

To the best of our knowledge, none of the directors, executive officers or shareholders that either: (i) beneficially owned; or (ii) exercised direction or control of, directly or indirectly, over 10% of any class of our outstanding securities, nor their associates or affiliates, have or have had within the three most recently completed financial years, any material interests in material transactions which have affected, or will materially affect, the company.

Other information about our directors and officers

None of our directors or officers, or a shareholder with significant holdings that could materially affect control of us, is or was a director or executive officer of another company in the past 10 years that:

 

•

was the subject of a cease trade or similar order, or an order denying that company any exemption under securities legislation, for more than 30 consecutive days while the director or executive officer held that role with the company

 

•

was involved in an event that resulted in the company being subject to one of the above orders after the director or executive officer no longer held that role with the company

 

•

while acting in that capacity, or within a year of acting in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of that company, except for Nancy Hopkins who from 2003 to 2014 was a director of Growthworks Canadian Fund Ltd. which has obtained court protection under the Companies’ Creditors Arrangement Act.

None of them in the past 10 years:

 

•

became bankrupt

 

•

made a proposal under any legislation relating to bankruptcy or insolvency

 

•

has been subject to or launched any proceedings, arrangement or compromise with any creditors, or

 

•

had a receiver, receiver manager or trustee appointed to hold any of their assets.

None of them has ever been subject to:

 

•

penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, or

 

•

any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

 

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About the audit and finance committee

Audit and finance committee charter

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

Composition of the audit and finance committee

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

Relevant education and experience

John Clappison, a corporate director, is the former managing partner of the Greater Toronto Area office of PricewaterhouseCoopers LLP (PwC). He is our committee chair and currently serves on the boards of two other publicly traded companies, on one of which he is the chair of their audit committee and one of which he is a member of their audit committee. Mr. Clappison has over 35 years of experience as a practicing chartered accountant and was an audit partner at PwC. He serves on boards of other private and not-for-profit organizations. Mr. Clappison is a chartered accountant and a Fellow of the Institute of Chartered Accountants of Ontario.

Ian Bruce, a corporate director, is the former co-chairman of the board of Peters & Co. Limited, an independent investment dealer. Over the course of his career at Peters & Co. Limited from 1998 to May 2011, Mr. Bruce was vice chairman, president and CEO, CEO and co-chairman. He was a past member of the Expert Panel on Securities Regulation for the Minister of Finance of Canada. Mr. Bruce was a board member and chair of the Investment Industry Association of Canada, and also served as a director of the public companies Hardy Oil & Gas plc from 2008 to 2012 and Taylor Gas Liquids Ltd. from 1997 to 2008. He currently serves on the board of two other publicly traded companies and three private companies. Mr. Bruce is a fellow of the Canadian Institute of Chartered Accountants of Alberta, a recognized Specialist in Valuation under Canadian CICA rules, and has his Corporate Finance Specialist designation in Canada and the UK.

Daniel Camus, a corporate director, is the former group chief financial officer and former head of strategy and international activities of Electricité de France SA (EDF), a France-based integrated energy operator active in the generation, distribution, transmission, supply and trading of electrical energy with international subsidiaries. He currently serves on the boards of four other publicly traded companies, on three of which he is the chair of the audit committee. Cameco’s board has approved Mr. Camus sitting on four audit committees of publicly traded companies, including Cameco. He is the Chief Financial Officer of the humanitarian finance organization, The Global Fund to Fight AIDS, Tuberculosis and Malaria. Mr. Camus received his PhD in Economics from Sorbonne University and an MBA in finance and economics from the Institute d’Études Politiques de Paris.

Catherine Gignac has been the principal of Catherine Gignac & Associates since 2011. Formerly, she was a mining equity research analyst with NCP Northland Capital Partners from 2009 to 2011 and prior to that she held the same position with Wellington West Capital Markets. She currently serves on the boards of three other publicly traded companies, on one of which she is the chair of its board and of its compensation committee, and on one of which she is the chair of its environmental, health, safety and technical committee. She has more than 30 years’ experience as a mining equity research analyst and geologist. She held senior positions with leading firms, including Merrill Lynch Canada, RBC Capital Markets, UBS Investment Bank and Dundee Capital Markets Inc. and Loewen Ondaatje McCutcheon Limited.

Nancy Hopkins is a partner with the law firm of McDougall Gauley, LLP in Saskatoon where she concentrates her practice on corporate, commercial and tax law. She currently serves on the board of one other publicly traded company and the Canadian Pension Plan Investment Board. She formerly served on the boards of the Canadian Institute of Chartered Accountants and the Saskatchewan Airport Authority as well as the board of governors of the University of Saskatchewan. Ms. Hopkins received her bachelor of commerce and law degrees from the University of Saskatchewan, and is an honorary member of the Institute of Chartered Accountants of Saskatchewan.

 

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Auditors’ fees

The table below shows the fees we paid to the external auditors for services in 2014 and 2013:

 

		2014 ($)				% of total fees (%)				2013 ($)				% of total fees (%)
Audit fees
Cameco			1,743,300				48.7				1,443,700				45.9
Subsidiaries			798,900				22.4				879,500				28.0
Total audit fees			2,542,200				71.1				2,323,200				73.9
Audit-related fees
Translation services			178,500				5.0				67,200				2.1
Pensions and other			177,800				5.0				104,300				3.3
Total audit-related fees			356,300				10.0				171,500				5.4
Tax fees
Compliance			307,800				8.6				252,500				8.0
Planning and advice			367,400				10.3				398,600				12.7
Total tax fees			675,200				18.9				651,100				20.7
All other fees			—				0.0				—				0.0
Total fees			3,573,700				100.0				3,145,800				100.0

Approving services

The audit and finance committee must pre-approve all services the external auditors will provide to make sure they remain independent. This is according to our audit and finance committee charter and consistent with our corporate governance practices. The audit and finance committee pre-approves services up to a specific limit. If we expect the fees to exceed the limit, or the external auditors to provide new audit or non-audit services that have not been pre-approved in the past, then this must be pre-approved separately.

Any service that is not generally pre-approved must be approved by the audit and finance committee before the work is carried out, or by the committee chair, or board chair in his or her absence, as long as the proposed service is presented to the full audit and finance committee at its next meeting.

The committee has adopted a written policy that describes the procedures for implementing these principles.

Interest of experts

Our auditor is KPMG LLP, independent chartered accountants, who have audited our 2014 financial statements.

KPMG LLP is independent within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Saskatchewan.

The individuals who are qualified persons for the purposes of NI 43-101 and employees of Cameco are listed under Mineral reserves and resources on page 67. As a group, they beneficially own, directly or indirectly, less than 1% of any class of the outstanding securities of Cameco and our associates and affiliates.

 

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Appendix A

Audit and finance committee of the Board of Directors

Mandate

Purpose

The primary purpose of the audit and finance committee (committee) is to assist the board of directors (board) in fulfilling its oversight responsibilities for (a) the accounting and financial reporting processes, (b) the internal controls, (c) the external auditors, including performance, qualifications, independence, and their audit of the corporation’s financial statements, (d) the performance of the corporation’s internal audit function, (e) financial matters and risk management of financial risks as delegated by the board, (f) the corporation’s process for monitoring compliance with laws and regulations (other than environmental and safety laws) and its code of conduct and ethics, and (g) prevention and detection of fraudulent activities. The committee shall also prepare such reports as required to be prepared by it by applicable securities laws.

In addition, the committee provides an avenue for communication between each of the internal auditor, the external auditors, management, and the board. The committee shall have a clear understanding with the external auditors that they must maintain an open and transparent relationship with the committee and that the ultimate accountability of the external auditors is to the board and the committee, as representatives of the shareholders. The committee, in its capacity as a committee of the board, subject to the requirements of applicable law, is directly responsible for the appointment, compensation, retention, and oversight of the external auditors.

The committee has the authority to communicate directly with the external auditors and internal auditor.

The committee shall make regular reports to the board concerning its activities and in particular shall review with the board any issues that arise with respect to the quality or integrity of the corporation’s financial statements, the performance and independence of the external auditors, the performance of the corporation’s internal audit function, or the corporation’s process for monitoring compliance with laws and regulations other than environmental and safety laws.

Composition

The board shall appoint annually, from among its members, a committee and its chair. The committee shall consist of at least three members and shall not include any director employed by the corporation.

Each committee member will be independent pursuant to the standards for independence adopted by the board.

Each committee member shall be financially literate with at least one member having accounting or related financial expertise, using the terms defined as follows:

“Financially literate” means the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the corporation’s financial statements; and

“Accounting or related financial expertise” means the ability to analyse and interpret a full set of financial statements, including the notes attached thereto, in accordance with Canadian generally accepted accounting principles.

In addition, where possible, at least one member of the committee shall qualify as an “audit committee financial expert” within the meaning of applicable securities law.

Members of the committee may not serve on the audit and finance committees of more than three public companies (including Cameco’s) without the approval of the board.

 

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Meetings

The committee will meet at least four times annually and as many additional times as the committee deems necessary to carry out its duties effectively. The committee will meet separately in private with the external auditors, the internal auditor and management at each regularly scheduled meeting.

A majority of the members of the committee shall constitute a quorum. No business may be transacted by the committee except at a meeting of its members at which a quorum of the committee is present.

The committee may invite such officers, directors and employees of the corporation as it may see fit from time to time to attend at meetings of the committee and assist thereat in the discussion and consideration of any matter.

A meeting of the committee may be convened by the chair of the committee, a member of the committee, the external auditors, the internal auditor, the chief executive officer or the chief financial officer. The secretary, who shall be appointed by the committee, shall, upon direction of any of the foregoing, arrange a meeting of the committee. The committee shall report to the board in a timely manner with respect to each of its meetings.

Duties and responsibilities

To carry out its oversight responsibilities, the committee shall:

Financial reporting process

 

1.

Review with management and the external auditors any items of concern, any proposed changes in the selection or application of major accounting policies and the reasons for the change, any identified risks and uncertainties, and any issues requiring management judgement, to the extent that the foregoing may be material to financial reporting.

 

2.

Consider any matter required to be communicated to the committee by the external auditors under applicable generally accepted auditing standards, applicable law and listing standards, including the external auditors’ report to the committee (and management’s response thereto) on: (a) all critical accounting policies and practices used by the corporation; (b) all material alternative accounting treatments of financial information within generally accepted accounting principles that have been discussed with management, including the ramifications of the use of such alternative treatments and disclosures and the treatment preferred by the external auditors; and (c) any other material written communications between the external auditors and management.

 

3.

Require the external auditors to present and discuss with the committee their views about the quality, not just the acceptability, of the implementation of generally accepted accounting principles with particular focus on accounting estimates and judgements made by management and their selection of accounting principles.

 

4.

Discuss with management and the external auditors (a) any accounting adjustments that were noted or proposed (i.e. immaterial or otherwise) by the external auditors but were not reflected in the financial statements, (b) any material correcting adjustments that were identified by the external auditors in accordance with generally accepted accounting principles or applicable law, (c) any communication reflecting a difference of opinion between the audit team and the external auditors’ national office on material auditing or accounting issues raised by the engagement, and (d) any “management” or “internal control” letter issued, or proposed to be issued, by the external auditors to the corporation.

 

5.	Discuss with management and the external auditors any significant financial reporting issues considered during the fiscal period and the method of resolution. Resolve disagreements between management and the external auditors regarding financial reporting.

 

6.

Review with management and the external auditors (a) any off-balance sheet financing mechanisms being used by the corporation and their effect on the corporation’s financial statements and (b) the effect of regulatory and accounting initiatives on the corporation’s financial statements, including the potential impact of proposed initiatives.

 

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7.

Review with management and the external auditors and legal counsel, if necessary, any litigation, claim or other contingency, including tax assessments, that could have a material effect on the financial position or operating results of the corporation, and the manner in which these matters have been disclosed or reflected in the financial statements.

 

8.

Review with the external auditors any audit problems or difficulties experienced by the external auditors in performing the audit, including any restrictions or limitations imposed by management, and management’s response. Resolve any disagreements between management and the external auditors regarding these matters.

 

9.	Review the results of the external auditors’ audit work including findings and recommendations, management’s response, and any resulting changes in accounting practices or policies and the impact such changes may have on the financial statements.

 

10.

Review and discuss with management and the external auditors the audited annual financial statements and related management discussion and analysis, make recommendations to the board with respect to approval thereof, before being released to the public, and obtain an explanation from management of all significant variances between comparable reporting periods.

 

11.	Review and discuss with management and the external auditors all interim unaudited financial statements and related interim management discussion and analysis and make recommendations to the board with respect to the approval thereof, before being released to the public.

 

12.	Obtain confirmation from the chief executive officer and the chief financial officer (and considering the external auditors’ comments, if any, thereon) to their knowledge:

 

(a)

that the audited financial statements, together with any financial information included in the annual MD&A and annual information form, fairly present in all material respects the corporation’s financial condition, cash flow and results of operation, as of the date and for the periods presented in such filings; and

 

(b)

that the interim financial statements, together with any financial information included in the interim MD&A, fairly present in all material respects the corporation’s financial condition, cash flow and results of operation, as of the date and for the periods presented in such filings.

 

13.

Review news releases to be issued in connection with the audited annual financial statements and related management discussion and analysis and the interim unaudited financial statements and related interim management discussion and analysis, before being released to the public. Discuss the type and presentation of information to be included in news releases (paying particular attention to any use of “pro-forma” or “adjusted” non-GAAP, information).

 

14.	Review any news release, before being released to the public, containing earnings guidance or financial information based upon the corporation’s financial statements prior to the release of such statements.

 

15.	Review the appointment of the chief financial officer and have the chief financial officer report to the committee on the qualifications of new key financial executives involved in the financial reporting process.

 

16.	Consult with the human resources and compensation committee on the succession plan for the chief financial officer and controller. Review the succession plans in respect of the chief financial officer and controller.

Internal Controls

 

1.	Receive from management a statement of the corporation’s system of internal controls over accounting and financial reporting.

 

2.	Consider and review with management, the internal auditor and the external auditors, the adequacy and effectiveness of internal controls over accounting and financial reporting within the corporation and any proposed significant changes in them.

 

3.	Consider and discuss the scope of the internal auditors and external auditors review of the corporation’s internal controls, and obtain reports on significant findings and recommendations, together with management responses.

 

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4.	Discuss, as appropriate, with management, the external auditors and the internal auditor, any major issues as to the adequacy of the corporation’s internal controls and any special audit steps in light of material internal control deficiencies.

 

5.

Review annually the disclosure controls and procedures, including (a) the certification timetable and related process and (b) the procedures that are in place for the review of the corporation’s disclosure of financial information extracted from the corporation’s financial statements and the adequacy of such procedures. Receive confirmation from the chief executive officer and the chief financial officer of the effectiveness of disclosure controls and procedures, and whether there are any significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the corporation’s ability to record, process, summarize and report financial information or any fraud, whether or not material, that involves management or other employees who have a significant role in the corporation’s internal control over financial reporting. In addition, receive confirmation from the chief executive officer and the chief financial officer that they are prepared to sign the annual and quarterly certificates required by applicable securities law.

 

6.	Review management’s annual report and the external auditors’ report on the assessment of the effectiveness of the corporation’s internal control over financial reporting.

 

7.	Receive a report, at least annually, from the reserves oversight committee of the board on the corporation’s mineral reserves.

External Auditors

 

(i)	External Auditors’ Qualifications and Selection

 

1.

Subject to the requirements of applicable law, be solely responsible to select, retain, compensate, oversee, evaluate and, where appropriate, replace the external auditors, who must be registered with agencies mandated by applicable law. The committee shall be entitled to adequate funding from the corporation for the purpose of compensating the external auditors for completing an audit and audit report.

 

2.	Instruct the external auditors that:

 

(a)

they are ultimately accountable to the board and the committee, as representatives of shareholders; and

 

(b)

they must report directly to the committee.

 

3.	Ensure that the external auditors have direct and open communication with the committee and that the external auditors meet regularly with the committee without the presence of management to discuss any matters that the committee or the external auditors believe should be discussed privately.

 

4.	Evaluate the external auditors’ qualifications, performance, and independence. As part of that evaluation:

 

(a)

at least annually, request and review a formal report by the external auditors describing: the firm’s internal quality-control procedures; any material issues raised by the most recent internal quality-control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps taken to deal with any such issues; and (to assess the auditors’ independence) all relationships between the external auditors and the corporation, including the amount of fees received by the external auditors for the audit services and for various types of non-audit services for the periods prescribed by applicable law; and

 

(b)

annually review and confirm with management and the external auditors the independence of the external auditors, including the extent of non-audit services and fees, the extent to which the compensation of the audit partners of the external auditors is based upon selling non-audit services, the timing and process for implementing the rotation of the lead audit partner, reviewing partner and other partners providing audit services for the corporation, whether there should be a regular rotation of the audit firm itself, and whether there has been a “cooling off” period of one year for any former employees of the external auditors who are

 

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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 and finance committee should consider the opinions of management and the internal auditor.

Conclusions on the independence of the external auditors should be reported to the board.

 

5.	Review and approve the corporation’s policies for the corporation’s hiring of employees and former employees of the external auditors. Such policies shall include, at minimum, a one-year hiring “cooling off” period.

 

(ii)	Other Matters

 

6.

Meet with the external auditors to review and approve the annual audit plan of the corporation’s financial statements prior to the annual audit being undertaken by the external auditors, including reviewing the year-to-year co-ordination of the audit plan and the planning, staffing and extent of the scope of the annual audit. This review should include an explanation from the external auditors of the factors considered by the external auditors in determining their audit scope, including major risk factors. The external auditors shall report to the committee all significant changes to the approved audit plan.

 

7.	Review and approve the basis and amount of the external auditors’ fees with respect to the annual audit in light of all relevant matters.

 

8.

Review and pre-approve all audit and non-audit service engagement fees and terms in accordance with applicable law, including those provided to the subsidiaries of the corporation by the external auditors or any other person in its capacity as external auditors of such subsidiary. Between scheduled committee meetings, the chair of the committee, on behalf of the committee, is authorised to pre-approve any audit or non-audit service engagement fees and terms. At the next committee meeting, the chair shall report to the committee any such pre-approval given. Establish and adopt procedures for such matters.

Internal Auditor

 

1.	Review and approve the appointment or removal of the internal auditor.

 

2.	Review and discuss with the external auditors, management, and internal auditor the responsibilities, budget and staffing of the corporation’s internal audit function.

 

3.	Review and approve the mandate for the internal auditor and the scope of annual work planned by the internal auditor, receive summary reports of internal audit findings, management’s response thereto, and reports on any subsequent follow-up to any identified weakness.

 

4.

Ensure that the internal auditor has direct and open communication with the committee and that the internal auditor meets regularly with the committee without the presence of management to discuss any matters that the committee or the internal auditor believe should be discussed privately, such as problems or difficulties which were encountered in the course of internal audit work, including restrictions on the scope of activities or access to required information, and any disagreements with management.

 

5.	Review and discuss with the internal auditor and management the internal auditor’s ongoing assessments of the corporation’s business processes and system of internal controls.

 

6.	Review the effectiveness of the internal audit function, including staffing, organizational structure and qualifications of the internal auditor and staff.

Compliance

 

1.	Monitor compliance by the corporation with all payments and remittances required to be made in accordance with applicable law, where the failure to make such payments could render the directors of the corporation personally liable.

 

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2.

The receipt of regular updates from management regarding compliance with laws and regulations and the process in place to monitor such compliance, excluding, however, legal compliance matters subject to the oversight of the safety, health and environment committee of the board. Review the findings of any examination by regulatory authorities and any external auditors’ observations relating to such matters.

 

3.	Establish and oversee the procedures in the code of conduct and ethics policy to address:

 

(a)

the receipt, retention and treatment of complaints received by the corporation regarding accounting, internal accounting or auditing matters; and

 

(b)

confidential, anonymous submissions by employees of concerns regarding questionable accounting and auditing matters.

Receive periodically a summary report from the senior vice-president governance, law and corporate secretary on such matters as required by the code of conduct and ethics.

 

4.

Review and recommend to the board for approval a code of conduct and ethics for employees, officers and directors of the corporation. Monitor management’s implementation of the code of conduct and ethics and the international business conduct policy and review compliance therewith by, among other things, obtaining an annual report summarizing statements of compliance by employees pursuant to such policies and reviewing the findings of any investigations of non-compliance. Periodically review the adequacy and appropriateness of such policies and make recommendations to the board thereon.

 

5.	Monitor management’s implementation of the anti-fraud policy; and review compliance therewith by, among other things, receiving reports from management on:

 

(a)

any investigations of fraudulent activity;

 

(b)

monitoring activities in relation to fraud risks and controls; and

 

(c)

assessments of fraud risk.

Periodically review the adequacy and appropriateness of the anti-fraud policy and make recommendations to the board thereon.

 

6.

Review all proposed related party transactions and situations involving a director’s, senior officer’s or an affiliate’s potential or actual conflict of interest that are not required to be dealt with by an “independent committee” pursuant to securities law rules, other than routine transactions and situations arising in the ordinary course of business, consistent with past practice. Between scheduled committee meetings, the chair of the committee, on behalf of the committee, is authorised to review all such transactions and situations. At the next committee meeting, the chair shall report the results of such review. Ensure that political and charitable donations conform with policies and budgets approved by the board.

 

7.	Monitor management of hedging, debt and credit, make recommendations to the board respecting policies for management of such risks, and review the corporation’s compliance therewith.

 

8.	Approve the review and approval process for the expenses submitted for reimbursement by the chief executive officer.

 

9.	Oversee management’s mitigation of material risks within the committee’s mandate and as otherwise assigned to it by the nominating, corporate governance and risk committee.

Financial Oversight

 

1.	Assist the board in its consideration and ongoing oversight of matters pertaining to:

 

(a)

capital structure and funding including finance and cash flow planning;

 

(b)

capital management planning and initiatives;

 

(c)

property and corporate acquisitions and divestitures including proposals which may have a material impact on the corporation’s capital position;

 

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(d)

the corporation’s annual budget and two-year business plan;

 

(e)

the activities of the corporation’s trading group including financial results, compliance with approval limits, any significant breaches of policies, and risk measures on significant positions and the portfolio in aggregate;

 

(f)

the corporation’s insurance program;

 

(g)

directors’ and officers’ liability insurance and indemnity agreements; and

 

(h)

matters the board may refer to the committee from time to time in connection with the corporation’s capital position.

Organizational matters

 

1.	The procedures governing the committee shall, except as otherwise provided for herein, be those applicable to the board committees as set forth in Part 7 of the General Bylaws of the corporation.

 

2.	The members and the chair of the committee shall be entitled to receive remuneration for acting in such capacity as the board may from time to time determine.

 

3.	The committee shall have the resources and authority appropriate to discharge its duties and responsibilities, including the authority to:

 

(a)

select, retain, terminate, set and approve the fees and other retention terms of special or independent counsel, accountants or other experts, as it deems appropriate; and

 

(b)

obtain appropriate funding to pay, or approve the payment of, such approved fees;

without seeking approval of the board or management.

 

4.

Any member of the committee may be removed or replaced at any time by the board and shall cease to be a member of the committee upon ceasing to be a director. The board may fill vacancies on the committee by appointment from among its members. If and whenever a vacancy shall exist on the committee, the remaining members may exercise all its powers so long as a quorum remains in office. Subject to the foregoing, each member of the committee shall remain as such until the next annual meeting of shareholders after that member’s election.

 

5.	The committee shall annually review and assess the adequacy of its mandate and recommend any proposed changes to the nominating, corporate governance and risk committee for recommendation to the board for approval.

 

6.	The committee shall participate in an annual performance evaluation, the results of which will be reviewed by the board.

 

7.	The committee shall perform any other activities consistent with this mandate, the corporation’s governing laws and the regulations of stock exchanges, as the committee or the board deems necessary or appropriate.

 

8.	A standing invitation will be issued to all non-executive directors to attend the financial oversight portion of each committee meeting.

 

2014 ANNUAL INFORMATION FORM    Page 131

EXHIBIT 99.2

Cameco Corporation

2014 Consolidated Audited Financial Statements

February 5, 2015

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Cameco Corporation

2014 consolidated financial statements

February 5, 2015

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Report of management’s accountability

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

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

In addition, management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. The internal control system includes an internal audit function and a code of conduct and ethics, which is communicated to all levels in the organization and requires all employees to maintain high standards in their conduct of the corporation’s affairs. Such systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate and that the Company’s assets are appropriately accounted for and adequately safeguarded. Management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the criteria established in “Internal Control – Integrated Framework (2013)” 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, 2014.

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 and finance 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 and finance committee. The audit and finance committee reviews the consolidated 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
President and Chief Executive Officer		Senior Vice-President and Chief Financial Officer
February 5, 2015		February 5, 2015

 

1

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Independent auditors’ report

To the Shareholders and Board of Directors of Cameco Corporation:

We have audited the accompanying consolidated financial statements of Cameco Corporation, which comprise the consolidated statements of financial position as at December 31, 2014 and December 31, 2013, the consolidated statements of earnings, statements of comprehensive income, changes in equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s responsibility for the consolidated financial statements

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

Auditors’ responsibility

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

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

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

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Cameco Corporation as at December 31, 2014 and December 31, 2013 and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Original signed by KPMG LLP

Chartered Accountants

February 5, 2015

Saskatoon, Canada

 

2

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Consolidated statements of earnings

 

For the years ended December 31										(Revised - note 6)
($Cdn thousands, except per share amounts)		Note				2014				2013
Revenue from products and services						$	2,397,532			$	2,438,723
Cost of products and services sold							1,420,768				1,549,238
Depreciation and amortization							338,983				282,756
Cost of sales							1,759,751				1,831,994
Gross profit							637,781				606,729
Administration							176,385				184,976
Impairment charges			10, 12, 13				326,693				70,159
Exploration							46,565				72,833
Research and development							5,044				7,302
Loss on disposal of assets			10				44,762				6,766
Earnings from operations							38,332				264,693
Finance costs			21				(77,122	)			(62,121	)
Losses on derivatives			28				(121,160	)			(61,970	)
Finance income							7,402				6,967
Share of loss from equity-accounted investees			13				(17,141	)			(14,107	)
Other income (expense)			22				50,591				(18,326	)
Earnings (loss) before income taxes							(119,098	)			115,136
Income tax recovery			23				(175,268	)			(117,230	)
Net earnings from continuing operations							56,170				232,366
Net earnings from discontinued operation			6				127,243				85,321
Net earnings						$	183,413			$	317,687
Net earnings (loss) attributable to:
Equity holders						$	185,234			$	318,495
Non-controlling interest							(1,821	)			(808	)
Net earnings						$	183,413			$	317,687
Earnings per common share attributable to equity holders
Continuing operations							0.15				0.59
Discontinued operation							0.32				0.22
Total basic earnings per share			24			$	0.47			$	0.81
Continuing operations							0.15				0.59
Discontinued operation							0.32				0.22
Total diluted earnings per share			24			$	0.47			$	0.81

See accompanying notes to consolidated financial statements.

 

3

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Consolidated statements of comprehensive income

 

For the years ended December 31										(Revised - note 6)
($Cdn thousands)		Note				2014				2013
Net earnings						$	183,413			$	317,687
Other comprehensive income (loss), net of taxes			23
Items that will not be reclassified to net earnings:
Remeasurements of defined benefit liability							(7,952	)			1,870
Remeasurements of defined benefit liability—discontinued operation							—				239,915
Items that are or may be reclassified to net earnings:
Exchange differences on translation of foreign operations							58,890				(10,792	)
Gains on derivatives designated as cash flow hedges—discontinued operation							—				190
Gains on derivatives designated as cash flow hedges transferred to net earnings—discontinued operation							(300	)			(3,982	)
Unrealized gains (losses) on available-for-sale assets							(613	)			28
Losses on available-for-sale assets transferred to net earnings							2				—
Other comprehensive income, net of taxes							50,027				227,229
Total comprehensive income						$	233,440			$	544,916
Comprehensive income from continuing operations						$	106,497			$	223,472
Comprehensive income from discontinued operation							126,943				321,444
Total comprehensive income						$	233,440			$	544,916
Other comprehensive income attributable to:
Equity holders						$	49,969			$	227,157
Non-controlling interest							58				72
Other comprehensive income for the period						$	50,027			$	227,229
Total comprehensive income (loss) attributable to:
Equity holders						$	235,203			$	545,652
Non-controlling interest							(1,763	)			(736	)
Total comprehensive income for the period						$	233,440			$	544,916

See accompanying notes to consolidated financial statements.

 

4

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Consolidated statements of financial position

 

As at December 31		Note				2014				2013
($Cdn thousands)
Assets
Current assets
Cash and cash equivalents						$	566,583			$	229,135
Accounts receivable			8				455,002				431,375
Current tax assets							3,096				2,598
Inventories			9				902,278				913,315
Supplies and prepaid expenses							130,406				177,632
Current portion of long-term receivables, investments and other			12				10,341				3,775
Total current assets							2,067,706				1,757,830
Property, plant and equipment			10				5,291,021				5,040,993
Goodwill and intangible assets			11				201,102				194,031
Long-term receivables, investments and other			12				423,280				287,548
Investments in equity-accounted investees			13				3,230				492,712
Deferred tax assets			23				486,328				266,203
Total non-current assets							6,404,961				6,281,487
Total assets						$	8,472,667			$	8,039,317
Liabilities and shareholders’ equity
Current liabilities
Bank overdraft			15			$	—			$	41,226
Accounts payable and accrued liabilities			14				316,258				437,941
Current tax liabilities							51,719				54,708
Short-term debt			15				—				50,230
Dividends payable							39,579				39,548
Current portion of other liabilities			17				87,883				60,685
Current portion of provisions			18				20,375				20,213
Total current liabilities							515,814				704,551
Long-term debt			16				1,491,198				1,293,383
Other liabilities			17				172,034				79,380
Provisions			18				825,935				570,700
Deferred tax liabilities			23				23,882				41,909
Total non-current liabilities							2,513,049				1,985,372
Shareholders’ equity
Share capital							1,862,646				1,854,671
Contributed surplus							196,815				186,382
Retained earnings							3,333,099				3,314,049
Other components of equity							51,084				(6,837	)
Total shareholders’ equity attributable to equity holders							5,443,644				5,348,265
Non-controlling interest							160				1,129
Total shareholders’ equity							5,443,804				5,349,394
Total liabilities and shareholders’ equity						$	8,472,667			$	8,039,317

Commitments and contingencies [notes 10,18, 23]

See accompanying notes to consolidated financial statements.

Approved by the board of directors

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

 

5

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Consolidated statements of changes in equity

 

		Attributable to equity holders
($Cdn thousands)		Share capital				Contributed surplus				Retained earnings				Foreign currency translation				Cash flow hedges				Available- for-sale assets				Total				Non- controlling interest				Total equity
Balance at January 1, 2014		$	1,854,671			$	186,382			$	3,314,049			$	(7,165	)		$	300			$	28			$	5,348,265			$	1,129			$	5,349,394
Net earnings			—				—				185,234				—				—				—				185,234				(1,821	)			183,413
Other comprehensive income			—				—				(7,952	)			58,832				(300	)			(611	)			49,969				58				50,027
Total comprehensive income for the year			—				—				177,282				58,832				(300	)			(611	)			235,203				(1,763	)			233,440
Share-based compensation			—				15,808				—				—				—				—				15,808				—				15,808
Share options exercised			7,975				(5,375	)			—				—				—				—				2,600				—				2,600
Dividends			—				—				(158,232	)			—				—				—				(158,232	)			—				(158,232	)
Transactions with owners-contributed equity			—				—				—				—				—				—				—				794				794
Balance at December 31, 2014		$	1,862,646			$	196,815			$	3,333,099			$	51,667			$	—			$	(583	)		$	5,443,644			$	160			$	5,443,804
Balance at January 1, 2013		$	1,851,507			$	168,952			$	2,913,134			$	3,699			$	4,092			$	—			$	4,941,384			$	580			$	4,941,964
Net earnings			—				—				318,495				—				—				—				318,495				(808	)			317,687
Other comprehensive loss			—				—				241,785				(10,864	)			(3,792	)			28				227,157				72				227,229
Total comprehensive income for the year			—				—				560,280				(10,864	)			(3,792	)			28				545,652				(736	)			544,916
Share-based compensation			—				19,008				—				—				—				—				19,008				—				19,008
Share options exercised			3,164				(1,578	)			—				—				—				—				1,586				—				1,586
Dividends			—				—				(158,177	)			—				—				—				(158,177	)			—				(158,177	)
Acquisition of non-controlling interest in subsidiary			—				—				—				—				—				—				—				97				97
Change in ownership interest in subsidiary			—				—				(1,188	)			—				—				—				(1,188	)			1,188				—
Balance at December 31, 2013		$	1,854,671			$	186,382			$	3,314,049			$	(7,165	)		$	300			$	28			$	5,348,265			$	1,129			$	5,349,394

See accompanying notes to consolidated financial statements.

 

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Consolidated statements of cash flows

 

For the years ended December 31										(Revised - note 6)
($Cdn thousands)		Note				2014				2013
Operating activities
Net earnings						$	183,413			$	317,687
Adjustments for:
Depreciation and amortization							338,983				282,756
Deferred charges							61,869				48,041
Unrealized losses on derivatives							40,569				39,059
Share-based compensation			26				15,808				19,008
Loss on disposal of assets							44,762				6,766
Finance costs			21				77,122				62,121
Finance income							(7,402	)			(6,967	)
Share of loss from equity-accounted investees			13				17,141				14,107
Impairment charges			10, 12, 13				326,693				70,159
Other expense (income)			22				(622	)			18,326
Discontinued operation			6				(127,243	)			—
Income tax recovery			23				(175,268	)			(117,230	)
Interest received							5,935				6,089
Income taxes paid							(233,716	)			(107,350	)
Income taxes refunded							—				10,993
Other operating items			25				(87,862	)			(139,526	)
Net cash provided by continuing operations							480,182				524,039
Net cash provided by discontinued operation			6				—				5,845
Net cash provided by operations							480,182				529,884
Investing activities
Additions to property, plant and equipment			10				(480,108	)			(645,651	)
Acquisitions, net of cash			7				—				(133,924	)
Repayment of debt acquired on acquisition of business			7				—				(118,068	)
Decrease in short-term investments							—				49,535
Decrease (increase) in long-term receivables, investments and other							11,569				(6,373	)
Proceeds from sale of property, plant and equipment							701				67
Net cash used in investing (continuing operations)							(467,838	)			(854,414	)
Net cash provided by investing (discontinued operation)			6				447,096				—
Net cash used in investing							(20,742	)			(854,414	)
Financing activities
Increase in debt			16				496,476				14,655
Decrease in debt			15, 16				(351,046	)			(33,114	)
Interest paid							(78,144	)			(65,908	)
Contributions from non-controlling interest							794				—
Proceeds from issuance of shares, stock option plan							6,228				2,475
Dividends paid							(158,200	)			(158,165	)
Net cash used in financing							(83,892	)			(240,057	)
Increase (decrease) in cash and cash equivalents net of bank overdraft, during the year							375,548				(564,587	)
Exchange rate changes on foreign currency cash balances							3,126				2,997
Cash and cash equivalents, net of bank overdraft, beginning of year							187,909				749,499
Cash and cash equivalents, net of bank overdraft, end of year						$	566,583			$	187,909
Cash and cash equivalents is comprised of:
Cash						$	86,664			$	59,183
Cash equivalents							479,919				169,952
Cash and cash equivalents						$	566,583			$	229,135
Bank overdraft							—				(41,226	)
Cash and cash equivalents and bank overdraft						$	566,583			$	187,909

See accompanying notes to consolidated financial statements.

 

7

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Notes to consolidated financial statements

For the years ended December 31, 2014 and 2013

1. Cameco Corporation

Cameco Corporation is incorporated under the Canada Business Corporations Act. The address of its registered office is 2121 11th Street West, Saskatoon, Saskatchewan, S7M 1J3. The consolidated financial statements as at and for the year ended December 31, 2014 comprise Cameco Corporation and its subsidiaries (collectively, the Company or Cameco) and the Company’s interests in associates and joint arrangements. The Company is primarily engaged in the exploration for and the development, mining, refining, conversion, fabrication and trading of uranium for sale as fuel for generating electricity in nuclear power reactors in Canada and other countries.

2. Significant accounting policies

A. Statement of compliance

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

These consolidated financial statements were authorized for issuance by the Company’s board of directors on February 5, 2015.

B. Basis of presentation

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

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

 

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

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

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

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

 

8

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C. Consolidation principles

i. Business combinations

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

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

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

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

ii. Subsidiaries

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

iii. Investments in equity-accounted investees

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

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

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

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

iv. Joint arrangements

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

 

9

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

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

v. Transactions eliminated on consolidation

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

D. Foreign currency translation

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

i. Foreign currency transactions

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

ii. Foreign operations

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

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

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

 

10

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E. Cash and cash equivalents

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

F. Short-term investments

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

G. Inventories

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

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

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

H. Property, plant and equipment

i. Buildings, plant and equipment and other

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

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

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

ii. Mineral properties and mine development costs

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

The production stage is reached when a mine property is in the condition necessary for it to be capable of operating in the manner intended by management. The criteria used to assess the start date of the production stage are determined based on the nature of each mine construction project, including the complexity of a mine site. A range of factors is considered when determining whether the production stage has been reached, which includes, but is not limited to, the demonstration of sustainable production at or near the level intended (such as the demonstration of continuous throughput levels at or above a target percentage of the design capacity).

 

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iii. Depreciation

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

 

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

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 reporting period and are adjusted if appropriate.

iv. Borrowing costs

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

v. Repairs and maintenance

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

I. Goodwill and intangible assets

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

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

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

J. Leased assets

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

 

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accounting policy applicable to that asset. 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.

Lease agreements that do not meet the recognition criteria of a finance lease are classified and recognized as operating leases and are not recognized in the Company’s consolidated statements of financial position. Payments made under operating leases are charged to income on a straight-line basis over the lease term.

K. Finance income and finance costs

Finance income comprises interest income on funds invested, gains on the disposal of available-for-sale financial assets, and changes in the fair value of non-derivative financial instruments. 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 non-derivative financial instruments.

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

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

L. Research and development costs

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

M. Impairment

i. Non-derivative financial assets

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

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

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

ii. Non-financial assets

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

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

 

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

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

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

N. Exploration and evaluation expenditures

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

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

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

O. Provisions

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

i. Environmental restoration

The mining, extraction and processing activities of the Company normally give rise to obligations for site closure and environmental restoration. Closure and restoration can include facility decommissioning and dismantling, removal or treatment of waste materials, as well as site and land restoration. The Company provides for the closure, reclamation and decommissioning of its operating sites in the financial period when the related environmental disturbance occurs, based on the estimated future costs using information available at the reporting date. Costs included in the provision comprise all closure and restoration activity expected to occur gradually over the life of the operation and at the time of closure. Routine operating

 

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costs that may impact the ultimate closure and restoration activities, such as waste material handling conducted as a normal part of a mining or production process, are not included in the provision.

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

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

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

ii. Waste disposal

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

P. Employee future benefits

i. Pension obligations

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

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

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

 

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

ii. Other post-retirement benefit plans

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

iii. Short-term employee benefits

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

iv. Termination benefits

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

v. Share-based compensation

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

For cash-settled plans, the fair value of the amount payable to employees is recognized as an expense, with a corresponding increase in liabilities, over the period that the employees unconditionally become entitled to payment. The liability is 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.

Q. Revenue recognition

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

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

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

 

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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.

R. Financial instruments

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

i. Non-derivative financial assets and financial liabilities

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

Fair value through profit or loss

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

Held-to-maturity

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

Loans and receivables

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

 

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Available-for-sale assets

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

Other financial liabilities

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

ii. Derivative financial instruments

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

The purpose of hedging transactions is to modify the Company’s exposure to one or more risks by creating an offset between changes in the fair value of, or the cash inflows attributable to, the hedged item and the hedging item. When hedge accounting is appropriate, the hedging relationship is designated as a fair value hedge, a cash flow hedge, or a foreign currency risk hedge related to a net investment in a foreign operation. The Company does not have any instruments that have been designated as hedge transactions at December 31, 2014.

Separable embedded derivatives

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

S. Income tax

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

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. Current tax assets and liabilities are measured at the amount expected to be paid or recovered from the taxation authorities.

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.

 

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

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

T. Share capital

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

U. Earnings per share

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

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

V. Segment reporting

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

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

W. Discontinued operations

A discontinued operation is a component of the Company that has either been disposed of or that is classified as held for sale. A component of the Company is comprised of operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the Company. Net earnings of a discontinued operation and any gain or loss on disposal are combined and presented as net earnings from discontinued operations in the consolidated statements of earnings.

3. Accounting standards

A. Changes in accounting policy

On January 1, 2014, Cameco adopted the following new standards and amendments to existing standards as issued by the IASB: IAS 32, Financial Instruments: Presentation (IAS 32), International Financial Reporting Interpretations Committee 21, Levies (IFRIC 21) and IAS 36, Impairment of Assets (IAS 36).

i. Financial assets and financial liabilities

Amendments to IAS 32 clarify matters regarding offsetting financial assets and financial liabilities as well as related disclosure requirements. As Cameco does not have a practice of offsetting its financial instruments, the adoption of IAS 32 has had no effect on the financial reporting of Cameco.

 

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ii. Levies

IFRIC 21 provides guidance on accounting for levies in accordance with IAS 37, Provisions, Contingent Liabilities and Contingent Assets. The interpretation defines a levy as an outflow from an entity imposed by a government in accordance with legislation and confirms that an entity recognizes a liability for a levy only when the triggering event specified in the legislation occurs. Cameco’s current accounting treatment for levies is consistent with the requirements of IFRIC 21, such that the adoption of IFRIC 21 has had no material impact on the financial reporting of Cameco.

iii. Disclosure of recoverable amounts

The amendments in IAS 36 reverse the unintended requirement in IFRS 13 to disclose the recoverable amount of every cash generating unit to which significant goodwill or indefinite-lived intangible assets have been allocated. Under these amendments, the recoverable amount is required to be disclosed only when an impairment loss has been recognized or reversed. As a result, the adoption of IAS 36 has had no effect on the financial reporting of Cameco.

B. New standards and interpretations not yet adopted

A number of new standards and amendments to existing standards are not yet effective for the year ended December 31, 2014, and have not been applied in preparing these consolidated financial statements. The following standards and amendments to existing standards have been published and are mandatory for Cameco’s accounting periods beginning on or after January 1, 2016, unless otherwise noted. Cameco does not intend to early adopt any of the following amendments to existing standards and does not expect the amendments to have a material impact on the financial statements, unless otherwise noted.

i. Property, plant and equipment and intangible assets

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

ii. Joint arrangements

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

iii. Sale or contribution of assets

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

iv. Noncurrent assets held for sale and discontinued operations

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

v. Financial instruments disclosures

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

 

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vi. Interim financial reporting

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

vii. Revenue

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

viii. Financial instruments

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

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

4. Determination of fair values

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

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

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

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

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

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

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

 

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

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

Note 10 – Property, plant and equipment

Note 11 – Goodwill and intangible assets

Note 13 – Equity-accounted investees

Note 26 – Share-based compensation plans

Note 28 – Financial instruments and risk management

5. Use of estimates and judgments

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

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

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

A. Recoverability of long-lived and intangible assets

Cameco assesses the carrying values of property, plant and equipment, and intangible assets when there is an indication of possible impairment. Goodwill and intangible assets not yet available for use or with indefinite useful lives are tested for impairment annually. If it is determined that carrying values of assets or goodwill cannot be recovered, the unrecoverable amounts are charged against current earnings. Recoverability is dependent upon assumptions and judgments regarding market conditions, costs of production, sustaining capital requirements and mineral reserves. Other assumptions used in the calculation of recoverable amounts are discount rates, future cash flows and profit margins. A material change in assumptions may significantly impact the potential impairment of these assets.

B. Cash generating units

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

C. Provisions for decommissioning and reclamation of assets

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

D. Income taxes

Cameco operates in a number of tax jurisdictions and is, therefore, required to estimate its income taxes in each of these tax jurisdictions in preparing its consolidated financial statements. In calculating income taxes, consideration is given to factors such as tax rates in the different jurisdictions, non-deductible expenses, valuation allowances, changes in tax law and

 

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management’s expectations of future operating results. Cameco estimates deferred income taxes based on temporary differences between the income and losses reported in its consolidated financial statements and its taxable income and losses as determined under the applicable tax laws. The tax effect of these temporary differences is recorded as deferred tax assets or liabilities in the consolidated financial statements. The calculation of income taxes requires the use of judgment and estimates. If these judgments and estimates prove to be inaccurate, future earnings may be materially impacted.

E. Commencement of production stage

Until a mining property is declared as being in the production stage, all costs related to its development are capitalized. The determination of the date on which a mine enters the production stage is a matter of judgment that impacts when capitalization of development costs ceases and depreciation of the mining property commences and is charged to earnings. Refer to note 2 (h)(ii) for further information on the criteria used to make this assessment.

F. Mineral reserves

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

G. Purchase price allocations

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

H. Determination of joint control

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

6. Discontinued operation

On March 27, 2014, Cameco completed the sale of its 31.6% limited partnership interest in Bruce Power L.P. (BPLP) which operates the four Bruce B nuclear reactors in Ontario. The aggregate sale price for Cameco’s interest in BPLP and certain related entities was $450,000,000. The sale has been accounted for effective January 1, 2014. Cameco received net proceeds of approximately $447,096,000 and realized an after tax gain of $127,243,000 on this divestiture.

 

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As a result of the transaction, Cameco presented the results of BPLP as a discontinued operation and revised its statement of earnings, statement of comprehensive income and statement of cash flows to reflect this change in presentation. Net earnings from this discontinued operation are as follows:

 

		2014				2013
Share of earnings from BPLP and related entities		$	—			$	112,793
Tax expense			—				27,472
			—				85,321
Gain on disposal of BPLP and related entities			144,912				—
Tax expense on disposal			17,669				—
			127,243				—
Net earnings from discontinued operation		$	127,243			$	85,321

7. Acquisitions

NUKEM Energy GmbH (NUKEM)

On January 9, 2013, Cameco completed the acquisition of NUKEM from Advent International and other shareholders, through the purchase of all the outstanding shares for cash consideration of $148,302,000 (US).

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

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

 

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

An advisory fee of $2,980,000 has been included in administration expense in the consolidated statement of earnings for the year ended December 31, 2013.

 

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8. Accounts receivable

 

		2014				2013
Trade receivables		$	428,850			$	391,749
Receivables due from related parties			—				13,400
HST/VAT receivables			19,523				15,344
Other receivables			6,629				10,882
Total		$	455,002			$	431,375

The Company’s exposure to credit and currency risks as well as impairment loss related to trade and other receivables, excluding harmonized sales tax (HST)/value added tax (VAT) receivables is disclosed in note 28.

9. Inventories

 

		2014				2013
Uranium
Concentrate		$	500,342			$	550,305
Broken ore			21,289				4,572
			521,631				554,877
NUKEM			251,942				208,217
Fuel services			128,705				150,221
Total		$	902,278			$	913,315

Cameco expensed $1,698,000,000 of inventory as cost of sales during 2014 (2013 - $1,690,000,000). Included in cost of sales is a $4,300,000 net recovery, resulting from the reversal of previous NUKEM inventory write-downs to reflect net realizable value (2013 - $14,000,000 write-down).

NUKEM enters into financing arrangements where future receivables arising from certain sales contracts are sold to financial institutions in exchange for cash. These arrangements require NUKEM to satisfy its delivery obligations under the sales contracts, which are recognized as deferred sales (note 17). In some of the arrangements, NUKEM is also required to pledge the underlying inventory as security against these performance obligations. As of December 31, 2014, NUKEM had $64,687,000 (US) (2013 -$31,763,000 (US)) of inventory pledged as security under financing arrangements.

 

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10. Property, plant and equipment

At December 31, 2014

 

		Land and buildings				Plant and equipment				Furniture and fixtures				Under construction				Exploration and evaluation				Total
Cost
Beginning of year		$	2,971,894			$	1,819,611			$	97,220			$	1,904,400			$	1,072,242			$	7,865,367
Additions			26,688				18,288				5,716				407,492				14,640				472,824
Transfers			143,639				152,564				17,171				(313,374	)			—				—
Change in reclamation provision			228,223				—				—				—				—				228,223
Disposals (b)			(902	)			(24,463	)			(1,111	)			(40,664	)			(10,984	)			(78,124	)
Effect of movements in exchange rates			54,194				18,721				1,076				4,646				8,817				87,454
End of year			3,423,736				1,984,721				120,072				1,962,500				1,084,715				8,575,744
Accumulated depreciation and impairment
Beginning of year			1,491,681				1,019,529				81,216				70,159				161,789				2,824,374
Depreciation charge			185,238				111,980				23,574				94				161				321,047
Transfers			(4,190	)			4,190				—				—				—				—
Disposals			(678	)			(16,736	)			(336	)			—				(7,160	)			(24,910	)
Impairment charge (a)			66,084				38,968				—				21,368				—				126,420
Effect of movements in exchange rates			31,391				7,038				(353	)			—				(284	)			37,792
End of year			1,769,526				1,164,969				104,101				91,621				154,506				3,284,723
Net book value at December 31, 2014		$	1,654,210			$	819,752			$	15,971			$	1,870,879			$	930,209			$	5,291,021

At December 31, 2013

 

		Land and buildings				Plant and equipment				Furniture and fixtures				Under construction				Exploration and evaluation				Total
Cost
Beginning of year		$	2,722,059			$	1,663,769			$	89,868			$	1,679,571			$	1,126,254			$	7,281,521
Acquisitions [note 7]			—				1,070				—				—				—				1,070
Additions			54,899				18,299				485				528,547				9,131				611,361
Change in reclamation provision			1,958				—				—				—				—				1,958
Transfers			161,042				141,018				6,929				(308,989	)			—				—
Disposals			(1,467	)			(14,294	)			(578	)			—				(131	)			(16,470	)
Effect of movements in exchange rates			33,403				9,749				516				5,271				(63,012	)			(14,073	)
End of year			2,971,894				1,819,611				97,220				1,904,400				1,072,242				7,865,367
Accumulated depreciation and impairment
Beginning of year			1,305,639				918,829				71,903				—				168,000				2,464,371
Depreciation charge			169,561				105,101				9,531				—				258				284,451
Transfers			(185	)			692				(507	)			—				—				—
Disposals			(378	)			(9,104	)			(155	)			—				—				(9,637	)
Impairment charges (c)			28				344				—				70,159				7,160				77,691
Effect of movements in exchange rates			17,016				3,667				444				—				(13,629	)			7,498
End of year			1,491,681				1,019,529				81,216				70,159				161,789				2,824,374
Net book value at December 31, 2013		$	1,480,213			$	800,082			$	16,004			$	1,834,241			$	910,453			$	5,040,993

 

 

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Cameco has contractual capital commitments of approximately $99,000,000 at December 31, 2014. Certain of the contractual commitments may contain cancellation clauses, however the Company discloses the commitments based on management’s intent to fulfill the contract. The majority of this amount is expected to be incurred in 2015.

(a) During 2014, Cameco recognized a $126,420,000 impairment charge relating to its Rabbit Lake operation in northern Saskatchewan, which is part of its uranium segment. Due to the deferral of various projects that were related to planned production over the remaining life of the Eagle Point mine, the Company concluded it was appropriate to recognize an impairment charge. The amount of the charge was determined as the excess of the carrying value over the recoverable amount. The recoverable amount of the mine was determined to be $28,570,000 based on a fair value less costs to sell model, which incorporated the future cash flows expected to be derived from the mine. It is categorized as a non-recurring level 3 fair value measurement.

The discount rate used in the fair value less costs to sell calculation was 8% and was determined based on a market participant’s incremental borrowing cost, adjusted for the marginal return that the participant would expect to use on an investment in the mine. The recoverable amount is not sensitive to changes in the discount rate. Other key assumptions include uranium price forecasts and operating and capital cost forecasts. Uranium prices applied in the calculation were based on approved internal price forecasts, which reflect management’s expectation of prices that a market participant would use. Operating and capital cost forecasts have been determined based on management’s internal cost estimates. A $1/lb decrease in the uranium price assumption decreases the recoverable amount by $17,600,000.

(b) Due to extended low market conditions and continued efforts to reduce costs, certain projects were re-evaluated. As a result, the Company wrote off $40,664,000 of assets under construction on these projects.

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

11. Goodwill and intangible assets

A. Reconciliation of carrying amount

At December 31, 2014

 

		Goodwill				Contracts				Intellectual property				Patents				Total
Cost
Beginning of year		$	93,998			$	93,102			$	118,819			$	9,298			$	315,217
Effect of movements in exchange rates			8,528				8,447				—				843				17,818
End of year			102,526				101,549				118,819				10,141				333,035
Accumulated amortization
Beginning of year			—				82,960				36,940				1,286				121,186
Amortization charge			—				(1,438	)			4,052				531				3,145
Effect of movements in exchange rates			—				7,456				—				146				7,602
End of year			—				88,978				40,992				1,963				131,933
Net book value at December 31, 2014		$	102,526			$	12,571			$	77,827			$	8,178			$	201,102

 

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At December 31, 2013

 

		Goodwill				Contracts				Intellectual property				Patents				Total
Cost
Beginning of year		$	—			$	—			$	118,819			$	8,697			$	127,516
Additions [note 7]			87,460				86,627				—				—				174,087
Effect of movements in exchange rates			6,538				6,475				—				601				13,614
End of year			93,998				93,102				118,819				9,298				315,217
Accumulated amortization
Accumulated amortization			—				—				33,694				721				34,415
Amortization charge			—				79,609				3,246				494				83,349
Effect of movements in exchange rates			—				3,351				—				71				3,422
End of year			—				82,960				36,940				1,286				121,186
Net book value at December 31, 2013		$	93,998			$	10,142			$	81,879			$	8,012			$	194,031

B. Amortization

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

 

2015				2016				2017				2018				2019				2020				2021				2022				Total
	$2,540				2,897				994				1,091				975				871				777				692			$	10,837

C. Impairment test

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

The recoverable amount of NUKEM was estimated based on a value in use calculation, which involved discounting the future cash flows expected to be generated from the continuing use of the CGU. The estimated recoverable amount of NUKEM exceeded its carrying amount by approximately $73,500,000 (US) and therefore no impairment loss was recognized.

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

 

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		2014
Discount rate (pre-tax)			12.8	%
Discount rate (post-tax)			8.8	%
Terminal value growth rate			2.4	%

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

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

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

 

		Change in assumption		Amount of decrease
Discount rate		1% increase		$	31,215
Terminal value growth rate		1% decrease			25,642
Uranium prices		$1/lb decrease			5,829
Perpetual annual cash flow		$1 million (US) decrease			10,947

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

12. Long-term receivables, investments and other

 

		2014				2013
Investments in equity securities [note 28]		$	6,601			$	22,805
Derivatives [note 28]			3,889				7,391
Advances receivable from JV Inkai LLP [note 33]			91,672				95,319
Investment tax credits			90,658				82,177
Amounts receivable related to tax dispute [note 23]			211,604				59,475
Other			29,197				24,156
			433,621				291,323
Less current portion			(10,341	)			(3,775	)
Net		$	423,280			$	287,548

During 2014, GoviEx Uranium (GoviEx) became listed on the Canadian Securities Exchange. With the availability of a quoted market price, Cameco determined that there was a significant decline in the fair value of its investment in GoviEx and as a result, an impairment charge of $16,658,000 was recorded.

 

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13. Equity-accounted investees

 

		2014				2013
Interest in BPLP [note 6]		$	—			$	294,537
Interest in GE-Hitachi Global Laser Enrichment LLC (GLE)			—				185,162
Interests in other associates			3,230				7,104
Interests in other joint ventures			—				5,909
		$	3,230			$	492,712

Associates

i. GLE

Cameco owns a 24% interest in GLE and accounts for it under the equity method of accounting. During the year, a decision was made by the majority partner of GLE to significantly reduce funding of the project. As a result, Cameco recognized an impairment charge of $183,615,000, which represented the full amount of Cameco’s investment.

GLE primarily operates in North Carolina and is testing a third-generation technology that, if successful, will use lasers to commercially enrich uranium. The technology is unique to the industry, is inherently risky and the significant reduction of funding introduces a further level of risk to this project. Because the funding reduction significantly jeopardizes the viability of the project, Cameco determined the fair value less costs to sell to be nil and as such recognized an impairment charge for the full amount of the asset. Future contributions to the project will be reflected in net earnings.

The following table summarizes the financial information of GLE:

 

		2014				2013
Current assets		$	—			$	526
Non-current assets			—				206,107
Current liabilities			—				(5,280	)
Net assets (100%)		$	—			$	201,353
Cameco’s share of net assets (24%)		$	—			$	48,325
Acquisition fair value and other adjustments			—				136,837
Carrying amount in the statement of financial position		$	—			$	185,162
Loss from operations and comprehensive loss		$	(55,279	)		$	(54,477	)
Cameco’s share of loss from operations and comprehensive loss (24%)		$	(13,267	)		$	(13,074	)

ii. Other associate

Cameco has one other associate. The following table summarizes the carrying amount and share of loss and other comprehensive income of this associate:

 

		2014				2013
Carrying amount of associate		$	3,230			$	7,104
Share of loss from operations and comprehensive loss		$	(3,874	)		$	(1,033	)

At December 31, 2014, the quoted value of the Company’s share in this associate that has shares listed on a recognized stock exchange was $14,256,000 (2013 - $19,758,000).

 

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14. Accounts payable and accrued liabilities

 

		2014				2013
Trade payables		$	183,120			$	346,390
Non-trade payables			114,174				72,857
Payables due to related parties			18,964				18,694
Total		$	316,258			$	437,941

The Company’s exposure to currency and liquidity risk related to trade and other payables is disclosed in note 28.

15. Short-term debt

 

		2014				2013
Promissory note payable		$	—			$	10,601
Commercial paper			—				24,974
NUKEM short-term loans			—				14,655
Total		$	—			$	50,230

In 2008, a promissory note in the amount of $73,344,000 (US) was issued to finance the acquisition of GLE. No balance was outstanding under this promissory note at December 31, 2014. At December 31, 2013, $9,967,000 (US) of principal was outstanding.

Cameco borrows directly in the commercial paper market. At December 31, 2014, there was no commercial paper outstanding (2013 - $24,974,000).

JV Inkai LLP (Inkai) has a $20,000,000 (US) revolving credit facility that is available until August 11, 2015. While Cameco’s share of this facility is $12,000,000 (US), it acts as a guarantor for the full amount of the facility. No balance was outstanding under this facility at December 31, 2014 or December 31, 2013.

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

As of December 31, 2014, there were no amounts withdrawn against the facility. At December 31, 2013 NUKEM had drawn a total of €38,130,000 on the facility, of which €28,130,000 was drawn in the form of bank overdrafts and €10,000,000 in the form of short-term loans. As of December 31, 2014, NUKEM has $356,000 (US) in letters of credit outstanding against the facility in support of performance obligations under outstanding delivery contracts (2013 - $693,000 (US)).

The terms of the facility contain a financial covenant that requires NUKEM to maintain a minimum working capital to debt ratio of 1.35. The facility also stipulates Cameco as a guarantor for NUKEM’s withdrawals and requires the Company to maintain a credit rating of at least BBB-. Failure to comply with these covenants could result in cancellation of the facility and accelerated payment of any outstanding amounts. As of December 31, 2014, NUKEM and Cameco were in compliance with the covenants and the Company does not expect its operating and investing activities in 2015 to be constrained by them.

 

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16. Long-term debt

 

		2014				2013
Unsecured debentures
Series C - 4.70% debentures redeemed July 16, 2014		$	—			$	299,537
Series D - 5.67% debentures due September 2, 2019			497,465				497,003
Series E - 3.75% debentures due November 14, 2022			397,857				397,626
Series F - 5.09% debentures due November 14, 2042			99,230				99,217
Series G - 4.19% debentures due June 24, 2024			496,646				—
Total		$	1,491,198			$	1,293,383

On June 24, 2014, Cameco issued $500,000,000 of Series G debentures and announced the early redemption of the outstanding Series C debentures. The Series G debentures bear interest at a rate of 4.19% per annum. The net proceeds of the issue after deducting expenses were approximately $496,400,000. The debentures mature on June 24, 2024 and are being amortized at an effective interest rate of 4.28%. The $300,000,000 principal amount of the Series C debentures was redeemed on July 16, 2014. The company incurred total charges of $12,135,000 in relation to the early redemption of these debentures (note 21).

Cameco has a $1,250,000,000 unsecured revolving credit facility that is available until November 1, 2018. Upon mutual agreement, the facility can be extended for an additional year on the anniversary date. In addition to direct borrowings under the facility, up to $100,000,000 can be used for the issuance of letters of credit and, to the extent necessary, it may be used to provide liquidity support for the Company’s commercial paper program. The agreement also provides the ability to increase the revolving credit facility above $1,250,000,000 by increments no less than $50,000,000, to a total of $1,750,000,000. The facility ranks equally with all of Cameco’s other senior debt. As of December 31, 2014, there were no amounts outstanding under this facility.

Cameco has $1,068,420,000 (2013—$824,745,000) in letter of credit facilities. Outstanding and committed letters of credit at December 31, 2014 amounted to $950,716,000 (2013—$798,774,000), the majority of which relate to future decommissioning and reclamation liabilities (note 18).

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, 2014, Cameco was in compliance with the covenant and does not expect its operating and investing activities in 2015 to be constrained by it.

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

 

2015		2016				2017				2018				2019				Thereafter				Total
$—			—				—				—				497,465				993,733			$	1,491,198

 

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17. Other liabilities

 

		2014				2013
Deferred sales		$	123,298			$	55,126
Derivatives [note 28]			67,916				30,923
Accrued pension and post-retirement benefit liability [note 27]			61,670				45,931
Other			7,033				8,085
			259,917				140,065
Less current portion			(87,883	)			(60,685	)
Net		$	172,034			$	79,380

Deferred sales includes $92,299,000 (US) (2013—$36,725,000 (US)) of performance obligations relating to financing arrangements entered into by NUKEM (note 9).

18. Provisions

 

		Reclamation				Waste disposal				Total
Beginning of year		$	573,942			$	16,971			$	590,913
Changes in estimates and discount rates			227,206				2,574				229,780
Provisions used during the period			(13,746	)			(1,679	)			(15,425	)
Unwinding of discount			20,242				429				20,671
Impact of foreign exchange			20,371				—				20,371
End of year		$	828,015			$	18,295			$	846,310
Current		$	18,703			$	1,672			$	20,375
Non-current			809,312				16,623				825,935
		$	828,015			$	18,295			$	846,310

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 $874,314,000 (2013—$823,493,000). The expected timing of these outflows is based on life-of-mine plans with the majority of expenditures expected to occur after 2021. 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 $910,902,000 (2013—$767,635,000) in the form of letters of credit to satisfy current regulatory requirements.

The reclamation provision relates to the following segments:

 

		2014				2013
Uranium		$	682,769			$	468,546
Fuel Services			145,246				105,396
Total		$	828,015			$	573,942

 

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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 $18,100,000 (2013—$18,250,000). These outflows are expected to occur within the next eight years.

19. Share capital

Authorized share capital:

 

•

Unlimited number of first preferred shares

 

•

Unlimited number of second preferred shares

 

•

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

 

•

One Class B share

A. Common shares

 

Number issued (number of shares)		2014				2013
Beginning of year			395,477,230				395,350,394
Issued:
Stock option plan [note 26]			315,292				126,836
Total			395,792,522				395,477,230

All issued shares are fully paid.

B. Class B share

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

C. Dividends

Dividends on Cameco Corporation common shares are declared in Canadian dollars. For the year ended December 31, 2014, the dividend declared per share was $0.40 (December 31, 2013—$0.40).

 

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20. Employee benefit expense

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

 

		2014				2013
Wages and salaries		$	353,254			$	353,772
Statutory and company benefits			66,456				62,287
Equity-settled share-based compensation [note 26]			21,048				24,289
Expenses related to defined benefit plans [note 27]			7,605				4,103
Contributions to defined contribution plans [note 27]			17,274				16,441
Cash-settled share-based compensation [note 26]			(1,616	)			1,272
Total		$	464,021			$	462,164

21. Finance costs

 

		2014				2013
Interest on long-term debt		$	67,614			$	66,273
Unwinding of discount on provisions			20,671				16,391
Other charges			6,531				6,286
Loss on redemption of Series C debentures [note 16]			12,135				—
Foreign exchange gains			(34,731	)			(27,378	)
Interest on short-term debt			4,902				549
Total		$	77,122			$	62,121

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

22. Other income (expense)

 

		2014				2013
Contract settlement		$	65,557			$	—
Contract termination fee			(18,304	)			—
Loss on sale of investments			—				(14,952	)
Other			3,338				(3,374	)
Total		$	50,591			$	(18,326	)

During the year, Cameco recorded an early termination fee of $18,304,000, incurred as a result of the cancellation of our toll conversion agreement with Springfields Fuels Ltd., which was to expire in 2016.

In addition, Cameco recorded a gain with respect to a long-term supply contract with one of its utility customers. The $65,557,000 reflected as income from contract settlement relates to deliveries that the customer refused to take in the years 2012 through 2017. This represents the full amount to be received in relation to this contract dispute.

 

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23. Income taxes

A. Significant components of deferred tax assets and liabilities

 

		Recognized in earnings								As at December 31
		2014				2013				2014				2013
Assets
Inventories		$	—			$	(3,250	)		$	—			$	—
Provision for reclamation			75,732				9,084				251,045				174,708
Foreign exploration and development			(807	)			(2,711	)			6,103				6,910
Income tax losses			136,294				73,412				335,856				199,412
Defined benefit plan actuarial losses			—				—				5,813				8,807
Long-term investments and other			1,424				8,672				67,060				59,628
Deferred tax assets			212,643				85,207				665,877				449,465
Liabilities
Property, plant and equipment			(1,334	)			(42,994	)			182,841				184,930
Inventories			(15,719	)			(15,825	)			20,590				37,139
Other			(3,102	)			(24,918	)			—				3,102
Deferred tax liabilities			(20,155	)			(83,737	)			203,431				225,171
Net deferred tax asset		$	232,798			$	168,944			$	462,446			$	224,294

 

Deferred tax allocated as		2014				2013
Deferred tax assets		$	486,328			$	266,203
Deferred tax liabilities			(23,882	)			(41,909	)
Net deferred tax asset		$	462,446			$	224,294

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

B. Movement in net deferred tax assets and liabilities

 

		2014				2013
Net deferred tax asset at beginning of year		$	224,294			$	188,143
Deferred tax liability on acquisition of NUKEM			—				(52,964	)
Recovery for the year in net earnings			246,558				185,830
Expense on discontinued operations			(13,761	)			(16,886	)
Recovery (expense) for the year in other comprehensive income			3,171				(79,427	)
Foreign exchange adjustments			2,184				(402	)
End of year		$	462,446			$	224,294

 

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C. Significant components of unrecognized deferred tax assets

 

		2014				2013
Income tax losses		$	130,300			$	72,656
Property, plant and equipment			1,404				54,759
Long-term investments and other			85,927				12,539
Total		$	217,631			$	139,954

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:

 

		2014				2013
Earnings from continuing operations before income taxes and non-controlling interest		$	(119,098	)		$	115,136
Combined federal and provincial tax rate			26.9	%			26.9	%
Computed income tax expense			(32,037	)			30,972
Increase (decrease) in taxes resulting from:
Difference between Canadian rates and rates applicable to subsidiaries in other countries			(225,368	)			(200,877	)
Change in unrecognized deferred tax assets			76,009				11,297
Other taxes			3,430				3,332
Share-based compensation plans			2,094				3,580
Change in tax provision related to transfer pricing			12,000				10,000
Non-deductible (non-taxable) capital amounts			(8,108	)			18,328
Other permanent differences			(3,288	)			6,138
Income tax recovery		$	(175,268	)		$	(117,230	)

E. Reassessments

In 2008, as part of the ongoing annual audits of Cameco’s Canadian tax returns, Canada Revenue Agency (CRA) disputed the transfer pricing structure and methodology used by Cameco and its wholly owned Swiss subsidiary, Cameco Europe Ltd., in respect of sale and purchase agreements for uranium products. From December 2008 to date, CRA issued notices of reassessment for the taxation years 2003 through 2009, which in aggregate have increased Cameco’s income for Canadian tax purposes by approximately $2,795,000,000. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229,300,000. Cameco believes it is likely that CRA will reassess Cameco’s tax returns for subsequent years on a similar basis and that these will require Cameco to make future remittances on receipt of the reassessments.

Using the methodology we believe that CRA will continue to apply and including the $2,795,000,000 already reassessed, we expect to receive notices of reassessment for a total of approximately $6,600,000,000 for the years 2003 through 2014, which would increase Cameco’s income for Canadian tax purposes and result in a related tax expense of approximately $1,900,000,000. In addition to penalties already imposed, CRA may continue to apply penalties to taxation years subsequent to 2009. As a result, we estimate that cash taxes and transfer pricing penalties would be between $1,450,000,000 and $1,500,000,000. In addition, we estimate there would be interest and instalment penalties applied that would be material to Cameco. While in dispute, we would be responsible for remitting 50% of the cash taxes and transfer pricing penalties (between $725,000,000 and $750,000,000), plus related interest and instalment penalties assessed, which would be material to Cameco.

 

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Under Canadian federal and provincial tax rules, the amount required to be remitted each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers. In light of our view of the likely outcome of the case, we expect to recover the amounts remitted to CRA, including cash taxes, interest and penalties totalling $211,604,000 already paid as at December 31, 2014 (December 31, 2013—$59,475,000) (note 12).

The case on the 2003 reassessment is expected to go to trial in 2016. If this timing is adhered to, we expect to have a Tax Court decision within six to 18 months after the trial is complete.

Having regard to advice from its external advisors, Cameco’s opinion is that CRA’s position is incorrect and Cameco is contesting CRA’s position and expects to recover any amounts remitted as a result of the reassessments. However, to reflect the uncertainties of CRA’s appeals process and litigation, Cameco has recorded a cumulative tax provision related to this matter for the years 2003 through the current period in the amount of $85,000,000. While the resolution of this matter may result in liabilities that are higher or lower than the reserve, management believes that the ultimate resolution will not be material to Cameco’s financial position, results of operations or liquidity in the year(s) of resolution. Resolution of this matter as stipulated by CRA would be material to Cameco’s financial position, results of operations or liquidity in the year(s) of resolution and other unfavourable outcomes for the years 2003 to date could be material to Cameco’s financial position, results of operations and cash flows in the year(s) of resolution.

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

F. Earnings and income taxes by jurisdiction

 

		2014				2013
Earnings (loss) from continuing operations before income taxes
Canada		$	(840,705	)		$	(715,361	)
Foreign			721,607				830,497
		$	(119,098	)		$	115,136
Current income taxes
Canada		$	(2,944	)		$	3,087
Foreign			74,234				65,513
		$	71,290			$	68,600
Deferred income tax recovery
Canada		$	(209,255	)		$	(150,474	)
Foreign			(37,303	)			(35,356	)
		$	(246,558	)		$	(185,830	)
Income tax recovery		$	(175,268	)		$	(117,230	)

G. Income tax losses

At December 31, 2014, income tax losses carried forward of $1,632,194,000 (2013—$968,347,000) are available to reduce taxable income. These losses expire as follows:

 

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Date of expiry		Canada				US				Other				Total
2019		$	—			$	—			$	4,686			$	4,686
2020			—				—				2,637				2,637
2029			—				23,839				—				23,839
2030			—				1,393				—				1,393
2031			94,257				20,332				—				114,589
2032			213,871				20,065				—				233,936
2033			252,781				34,206				—				286,987
2034			300,182				24,029				—				324,211
No expiry			—				—				639,916				639,916
		$	861,091			$	123,864			$	647,239			$	1,632,194

Included in the table above is $434,051,000 (2013 - $244,845,000) of temporary differences related to loss carry forwards where no future benefit is realized.

H. Other comprehensive income

Other comprehensive income 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 income:

For the year ended December 31, 2014

 

		Before tax				Income tax recovery (expense)				Net of tax
Remeasurements of defined benefit liability		$	(10,930	)		$	2,978			$	(7,952	)
Exchange differences on translation of foreign operations			58,890				—				58,890
Gains on derivatives designated as cash flow hedges transferred to net earnings—discontinued operation			(400	)			100				(300	)
Unrealized losses on available-for-sale assets			(707	)			94				(613	)
Losses on available-for-sale assets transferred to net earnings			3				(1	)			2
		$	46,856			$	3,171			$	50,027

For the year ended December 31, 2013

 

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

 

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24. 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 2014 was 395,740,117 (2013—395,427,548).

 

		2014				2013
Basic earnings per share computation
Net earnings attributable to equity holders		$	185,234			$	318,495
Weighted average common shares outstanding			395,740				395,428
Basic earnings per common share		$	0.47			$	0.81
Diluted earnings per share computation
Net earnings attributable to equity holders		$	185,234			$	318,495
Weighted average common shares outstanding			395,740				395,428
Dilutive effect of stock options			315				126
Weighted average common shares outstanding, assuming dilution			396,055				395,554
Diluted earnings per common share		$	0.47			$	0.81

25. Statements of cash flows

 

		2014				2013
Changes in non-cash working capital:
Accounts receivable		$	(18,063	)		$	26,972
Inventories			12,690				(107,221	)
Supplies and prepaid expenses			50,522				(60,738	)
Accounts payable and accrued liabilities			(141,905	)			(21,999	)
Reclamation payments			(15,425	)			(10,051	)
Amortization of purchase price allocation [note 7]			23,339				38,181
Other			980				(4,670	)
Other operating items		$	(87,862	)		$	(139,526	)

26. Share-based compensation plans

The Company has the following equity-settled plans:

A. Stock option plan

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

The aggregate number of common shares that may be issued pursuant to the Cameco stock option plan shall not exceed 43,017,198 of which 27,870,079 shares have been issued.

Stock option transactions for the respective years were as follows:

 

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(Number of options)		2014				2013
Beginning of year			9,817,443				9,517,840
Options granted			765,146				1,840,932
Options forfeited			(218,102	)			(587,653	)
Options expired			(1,696,189	)			(826,840	)
Options exercised [note 19]			(315,292	)			(126,836	)
End of year			8,353,006				9,817,443
Exercisable			5,819,252				6,279,629

Weighted average exercise prices were as follows:

 

		2014				2013
Beginning of year		$	29.95			$	31.20
Options granted			26.81				22.00
Options forfeited			30.69				31.61
Options expired			38.93				27.04
Options exercised			19.75				19.52
End of year		$	28.22			$	29.95
Exercisable		$	30.39			$	33.30

Total options outstanding and exercisable at December 31, 2014 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
$19.37 - 34.99			5,987,570				5.1			$	23.20				3,453,816			$	23.17
$35.00 - 54.38			2,365,436				2.5				40.93				2,365,436				40.93
			8,353,006												5,819,252

The foregoing options have expiry dates ranging from March 29, 2015 to March 2, 2022.

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

 

(Number of options)		2014				2013
Beginning of year			3,537,814				3,553,639
Options granted			765,146				1,840,932
Options forfeited			(58,686	)			(200,546	)
Options vested			(1,710,520	)			(1,656,211	)
End of year			2,533,754				3,537,814

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

 

41

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Cameco common share purchased on the open market, or cash at the board’s discretion, at the end of each three-year period if certain performance and vesting criteria have been met. The final value of the PSUs will be based on the value of Cameco common shares at the end of the three-year period and the number of PSUs that ultimately vest. Vesting of PSUs at the end of the three-year period will be based on total shareholder return over the three years, Cameco’s ability to meet its annual cash flow from operations targets and whether the participating executive remains employed by Cameco at the end of the three-year vesting period. As of December 31, 2014, the total number of PSUs held by the participants, after adjusting for forfeitures on retirement, was 620,654 (2013 - 559,401).

C. 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. In 2014, Cameco expanded the scope of the RSU plan to include additional employees of the Company. 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 RSUs carry vesting periods of one to three years, and the final value of the units will be based on the value of Cameco common shares at the end of the vesting periods. As of December 31, 2014, the total number of RSUs held by the participants was 246,394 (2013 - 70,000).

D. Employee share ownership plan

Cameco also has an employee share ownership plan, whereby both employee and Company contributions are used to purchase shares on the open market for employees. The Company’s contributions are expensed during the year of contribution. Under the plan, employees have the opportunity to participate in the program to a maximum of 6% of eligible earnings each year with Cameco matching the first 3% of employee-paid shares by 50%. Cameco contributes $1,000 of shares annually to each employee that is enrolled in the plan. Shares purchased with Company contributions and with dividends paid on such shares become unrestricted 12 months from the date on which such shares were purchased. At December 31, 2014, there were 3,704 participants in the plan (2013 - 3,718). The total number of shares purchased in 2014 with Company contributions was 280,765 (2013 - 278,349). In 2014, the Company’s contributions totalled $5,240,000 (2013 - $5,281,000).

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

 

		2014				2013
Stock option plan		$	7,802			$	13,322
Performance share unit plan			5,199				5,092
Restricted share unit plan			2,807				594
Employee share ownership plan			5,240				5,281
End of year		$	21,048			$	24,289

Fair value measurement of equity-settled plans

The fair value of the units granted through the PSU plan was determined based on Monte Carlo simulation and the fair value of options granted under the stock option plan was measured based on the Black-Scholes option-pricing model. The fair value of RSUs granted was determined based on their intrinsic value on the date of grant. Expected volatility was estimated by considering historic average share price volatility.

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

 

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		Stock option plan				RSUs				PSUs
Number of options granted			765,146				260,583				230,200
Average strike price		$	26.81			$	27.21				—
Expected dividend		$	0.40				—				—
Expected volatility			33	%			—				33	%
Risk-free interest rate			1.5	%			—				1.2	%
Expected life of option			4.4 years				—				3 years
Expected forfeitures			8	%			5	%			5	%
Weighted average grant date fair values		$	6.79			$	27.21			$	27.25

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

The Company has the following cash-settled plans:

A. Deferred share unit (DSU)

Cameco offers a DSU plan to non-employee directors. A DSU is a notional unit that reflects the market value of a single common share of Cameco. 60% of each director’s annual retainer is paid in DSUs. In addition, on an annual basis, directors can elect to receive 25%, 50%, 75% or 100% of the remaining 40% of their annual retainer and any additional fees in the form of DSUs. If a director meets their ownership requirements, the director may elect to take 25%, 50%, 75% or 100% of their annual retainer and any fees in cash, with the balance, if any, to be paid in DSUs. Each DSU fully vests upon award. The DSUs will be redeemed for cash upon a director leaving the board. The redemption amount will be based upon the weighted average of the closing prices of the common shares of Cameco on the TSX for the last 20 trading days prior to the redemption date multiplied by the number of DSUs held by the director. As of December 31, 2014, the total number of DSUs held by participating directors was 542,391 (2013 - 523,855).

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, 2014, the number of options held by participating employees was 223,053 (2013 - 239,885) with exercise prices ranging from $19.37 to $46.88 per share (2013 - $19.37 to $46.88) and a weighted average exercise price of $28.81 (2013 - $31.22).

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

 

		2014				2013
Deferred share unit plan		$	(1,493	)		$	1,192
Phantom stock option plan			(123	)			80
		$	(1,616	)		$	1,272

At December 31, 2014, a liability of $10,675,000 (2013 - $12,112,000) was included in the consolidated statements of financial position to recognize accrued but unpaid expenses for cash-settled plans.

 

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Fair value measurement of cash-settled plans

The fair value of the phantom stock option plan was measured based on the Black-Scholes option-pricing model. Expected volatility is estimated by considering historic average share price volatility. The inputs used in the measurement of the fair values of the phantom stock option plan at the grant and reporting dates were as follows:

 

		Grant date March 3, 2014				Reporting date December 31, 2014
Number of units			52,270				223,053
Average strike price		$	26.81			$	28.81
Expected dividend		$	0.40			$	0.40
Expected volatility			32	%			32	%
Risk-free interest rate			1.5	%			1.1	%
Expected life of option			3.5 years				3.3 years
Expected forfeitures			8	%			8	%
Weighted average measurement date fair values		$	5.10			$	2.01

27. Pension and other post-retirement benefits

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

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

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

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

Cameco expects to pay $537,000 in contributions and letter of credit fees to its defined benefit plans in 2015.

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

 

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

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

 

		Pension benefit plans								Other benefit plans
		2014				2013				2014				2013
Fair value of plan assets, beginning of year		$	15,402			$	20,167			$	—			$	—
Interest income on plan assets			717				791				—				—
Return on assets excluding interest income			188				(640	)			—				—
Employer contributions			10				123				—				—
Benefits paid			(5,420	)			(5,024	)			—				—
Administrative costs paid			(20	)			(15	)
Fair value of plan assets, end of year		$	10,877			$	15,402			$	—			$	—
Defined benefit obligation, beginning of year		$	44,386			$	37,497			$	16,947			$	15,317
Acquisition [note 7]			—				11,560				—				—
Current service cost			2,203				1,809				960				1,016
Interest cost			1,940				1,926				825				733
Actuarial loss (gain) arising from:
- demographic assumptions			971				1,752				106				558
- financial assumptions			5,992				(3,705	)			2,037				(1,474	)
- experience adjustment			2,192				(1,827	)			(180	)			1,471
Past service cost			2,374				(605	)			—				—
Benefits paid			(6,674	)			(5,558	)			(588	)			(674	)
Foreign exchange			(944	)			1,537				—				—
Defined benefit obligation, end of year		$	52,440			$	44,386			$	20,107			$	16,947
Defined benefit liability [note 17]		$	(41,563	)		$	(28,984	)		$	(20,107	)		$	(16,947	)

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
		2014				2013
Asset category (a)
Canadian equity securities			7	%			8	%
Global equity securities			13	%			15	%
Canadian fixed income			21	%			21	%
Other (b)			59	%			56	%
Total			100	%			100	%

 

(a)	The defined benefit plan assets contain no material amounts of related party assets at December 31, 2014 and 2013 respectively.

 

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

 

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

 

		Pension benefit plans								Other benefit plans
		2014				2013				2014				2013
Current service cost		$	2,203			$	1,809			$	960			$	1,016
Net interest cost			1,223				1,135				825				733
Past service cost			2,374				(605	)			—				—
Administration cost			20				15				—				—
Defined benefit expense [note 20]			5,820				2,354				1,785				1,749
Defined contribution pension expense [note 20]			17,274				16,441				—				—
Net pension and other benefit expense		$	23,094			$	18,795			$	1,785			$	1,749

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

 

		Pension benefit plans								Other benefit plans
		2014				2013				2014				2013
Actuarial loss (gain)		$	9,155			$	(3,780	)		$	1,963			$	555
Return on plan assets excluding interest income			(188	)			640				—				—
		$	8,967			$	(3,140	)		$	1,963			$	555

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

 

		Pension benefit plans								Other benefit plans
		2014				2013				2014				2013
Discount rate—obligation			3.4	%			4.4	%			3.9	%			4.8	%
Discount rate—expense			4.4	%			3.8	%			4.8	%			4.0	%
Rate of compensation increase			3.0	%			3.3	%			—				—
Initial health care cost trend rate			—				—				7.0	%			7.0	%
Cost trend rate declines to			—				—				5.0	%			5.0	%
Year the rate reaches its final level			—				—				2018				2018
Dental care cost trend rate			—				—				5.0	%			5.0	%

At December 31, 2014, the weighted average duration of the defined benefit obligation for the pension plans was 20.3 years (2013—16.6 years) and for the other benefit plans was 14.0 years (2013—13.2 years).

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

 

		Pension benefit plans								Other benefit plans
		Increase				Decrease				Increase				Decrease
Discount rate		$	(6,708	)		$	8,848			$	(2,124	)		$	2,610
Rate of compensation increase			2,889				(2,589	)			n/a				n/a

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

 

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The methods and assumptions used in preparing the sensitivity analyses are the same as the methods and assumptions used in determining the financial position of Cameco’s plans as at December 31, 2014. The sensitivity analyses are determined by varying the sensitivity assumption and leaving all other assumptions unchanged. Therefore, the sensitivity analyses do not recognize any interdependence in the assumptions. The methods and assumptions used in determining the above sensitivity are consistent with the methods and assumptions used in the previous year.

In addition, an increase of one year in the expected lifetime of plan participants in the pension benefit plans would increase the defined benefit obligation by $1,183,000.

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

28. 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 and nuclear fuel processing services, 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 and geopolitical events.

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

B. Foreign exchange risk

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

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 and option contracts to establish a price for future delivery of the foreign currency. These foreign currency contracts are not designated as hedges and are recorded at fair value with changes in fair value recognized in earnings. Cameco also has a natural hedge against US currency fluctuations because a portion of its annual cash outlays, including purchases of uranium and conversion services, is denominated in US dollars.

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

 

		Currency				Carrying value (Cdn)				Gain (loss)
Cash and cash equivalents			EUR			$	13,537			$	677
Cash and cash equivalents			USD				46,958				2,348
Accounts receivable			USD				346,331				17,317
Accounts receivable			EUR				14,798				740
Long-term receivables, investments and other			USD				91,672				4,584
Accounts payable and accrued liabilities			USD				(97,508	)			(4,875	)
Accounts payable and accrued liabilities			GBP				(18,999	)			(950	)
Net foreign currency derivatives			USD				(67,005	)			(104,479	)

A 5% strengthening of the Canadian dollar against the currencies above at December 31, 2014 would have had an equal but opposite effect on the amounts shown above, assuming all other variables remained constant.

C. Interest rate risk

The Company has a strategy of minimizing its exposure to interest rate risk by maintaining target levels of fixed and variable rate borrowings. The proportions of outstanding debt carrying fixed and variable interest rates are reviewed by senior management to ensure that these levels are within approved policy limits. At December 31, 2014, the proportion of Cameco’s outstanding debt that carries fixed interest rates is 80% (2013—84%).

Cameco is exposed to interest rate risk through its interest rate swap contracts whereby fixed rate payments on a notional amount of $300,000,000 of the Series D senior unsecured debentures were swapped for variable rate payments. The swaps terminate on September 2, 2019. Under the terms of the swaps, Cameco makes interest payments based on the three-month Canada Dealer Offered Rate plus an average margin of 3.7% and receives fixed interest payments of 5.67%. 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, 8.7%. At December 31, 2014, the fair value of Cameco’s interest rate swaps and caps was $2,978,000 (2013—$3,616,000).

 

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

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

 

		Gain (loss)
Interest rate contracts		$	(4,028	)
Advances receivable from Inkai			867

No amounts were withdrawn against NUKEM’s revolving loan facility as of December 31, 2014.

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

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

 

		2014				2013
Cash and cash equivalents		$	566,583			$	229,135
Accounts receivable			435,479				416,031
Advances receivable from Inkai [note 33]			91,672				95,319
Derivative assets			3,889				7,391

At December 31, 2014, 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, 2014:

 

		Total amount				Outstanding and committed				Amount available
Unsecured revolving credit facility		$	1,250,000			$	—			$	1,250,000
Letter of credit facility			1,068,420				950,716				117,704
Inkai revolving credit facility (Cameco’s share)			13,921				—				13,921
NUKEM multicurrency revolving loan facility			140,380				413				139,967

 

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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		$	316,258			$	316,258			$	316,258			$	—			$	—			$	—
Long-term debt			1,491,198				1,500,000				—				—				500,000				1,000,000
Foreign currency contracts			67,916				67,916				53,873				14,043				—				—
Total contractual repayments		$	1,875,372			$	1,884,174			$	370,131			$	14,043			$	500,000			$	1,000,000

 

		Total				Due in less than 1 year				Due in 1-3 years				Due in 3-5 years				Due after 5 years
Total interest payments on long-term debt		$	613,770			$	69,390			$	138,780			$	138,780			$	266,820

Measurement of fair values

A. Accounting classifications and fair values

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

As at December 31, 2014

 

		Fair value through profit or loss				Loans and receivables				Available for sale				Other financial liabilities				Total
Financial assets
Cash and cash equivalents		$	—			$	566,583			$	—			$	—			$	566,583
Accounts receivable [note 8]			—				455,002				—				—				455,002
Derivative assets [note 12]
Foreign currency contracts			911				—				—				—				911
Interest rate contracts			2,978				—				—				—				2,978
Investments in equity securities [note 12]			—				—				6,601				—				6,601
Advances receivable from Inkai [note 33]			—				91,672				—				—				91,672
			3,889				1,113,257				6,601				—				1,123,747
Financial liabilities
Accounts payable and accrued liabilities [note 14]			—				—				—				316,258				316,258
Derivative liabilities [note 17]
Foreign currency contracts			67,916				—				—				—				67,916
Long-term debt [note 16]			—				—				—				1,491,198				1,491,198
			67,916				—				—				1,807,456				1,875,372
Net		$	(64,027	)		$	1,113,257			$	6,601			$	(1,807,456	)		$	(751,625	)

 

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As at December 31, 2013

 

		Fair value through profit or loss				Loans and receivables				Available for sale				Other financial liabilities				Total
Financial assets
Cash and cash equivalents		$	—			$	229,135			$	—			$	—			$	229,135
Accounts receivable [note 8]			—				431,375				—				—				431,375
Derivative assets [note 12]
Foreign currency contracts			3,775				—				—				—				3,775
Interest rate contracts			3,616				—				—				—				3,616
Investments in equity securities [note 12]			—				—				22,805				—				22,805
Advances receivable from Inkai [note 33]			—				95,319				—				—				95,319
			7,391				755,829				22,805				—				786,025
Financial liabilities
Bank overdraft			41,226				—				—				—				41,226
Accounts payable and accrued liabilities [note 14]			—				—				—				437,941				437,941
Short-term debt [note 15]
Commercial paper			—				—				—				24,974				24,974
Promissory note			—				—				—				10,601				10,601
NUKEM short-term loan			—				—				—				14,655				14,655
Derivative liabilities [note 17]
Foreign currency contracts			30,907				—				—				—				30,907
Share purchase options			16				—				—				—				16
Long-term debt [note 16]			—				—				—				1,293,383				1,293,383
			72,149				—				—				1,781,554				1,853,703
Net		$	(64,758	)		$	755,829			$	22,805			$	(1,781,554	)		$	(1,067,678	)

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

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

As at December 31, 2014

 

						Fair value
		Carrying value				Level 1				Level 2				Total
Derivative assets [note 12]
Foreign currency contracts		$	911			$	—			$	911			$	911
Interest rate contracts			2,978				—				2,978				2,978
Investments in equity securities [note 12]			6,601				6,601				—				6,601
Derivative liabilities [note 17]
Foreign currency contracts			(67,916	)			—				(67,916	)			(67,916	)
Net		$	(57,426	)		$	6,601			$	(64,027	)		$	(57,426	)

 

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As at December 31, 2013

 

						Fair value
		Carrying value				Level 1				Level 2				Total
Derivative assets [note 12]
Foreign currency contracts		$	3,775			$	—			$	3,775			$	3,775
Interest rate contracts			3,616				—				3,616				3,616
Derivative liabilities [note 17]
Foreign currency contracts			(30,907	)			—				(30,907	)			(30,907	)
Share purchase options			(16	)			(16	)			—				(16	)
Net		$	(23,532	)		$	(16	)		$	(23,516	)		$	(23,532	)

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

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

B. Financial instruments measured at fair value

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

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

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

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

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

Cameco previously measured its investment in GoviEx at cost due to the unavailability of a quoted price in an active market. GoviEx is now listed on the Canadian Securities Exchange and as a result the Company has measured its investment at fair value as of the reporting date.

 

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C. Financial instruments not measured at fair value

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

Derivatives

The following table summarizes the fair value of derivatives and classification on the consolidated statements of financial position:

 

		2014				2013
Non-hedge derivatives:
Foreign currency contracts		$	(67,005	)		$	(27,132	)
Interest rate contracts			2,978				3,616
Share purchase options			—				(16	)
Net		$	(64,027	)		$	(23,532	)
Classification:
Current portion of long-term receivables, investmentsand other [note 12]		$	500			$	3,775
Long-term receivables, investments and other [note 12]			3,389				3,616
Current portion of other liabilities [note 17]			(53,873	)			(30,923	)
Other liabilities [note 17]			(14,043	)			—
Net		$	(64,027	)		$	(23,532	)

The following table summarizes the different components of the losses on derivatives included in net earnings:

 

		2014				2013
Non-hedge derivatives:
Foreign currency contracts		$	(126,069	)		$	(62,578	)
Interest rate contracts			4,893				624
Share purchase options			16				(16	)
Net		$	(121,160	)		$	(61,970	)

 

53

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29. Capital management

Cameco’s capital structure reflects our vision and the environment in which we operate. We seek growth through development and expansion of existing assets by acquisition. Our capital resources are managed to support achievement of our goals. The overall objectives for managing capital in 2014 remained unchanged from the prior comparative period.

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

The capital structure at December 31 was as follows:

 

		2014				2013
Bank overdraft		$	—			$	41,226
Long-term debt [note 16]			1,491,198				1,293,383
Short-term debt [note 15]			—				50,230
Cash and cash equivalents			(566,583	)			(229,135	)
Net debt			924,615				1,155,704
Non-controlling interest			160				1,129
Shareholders’ equity			5,443,644				5,348,265
Total equity			5,443,804				5,349,394
Total capital		$	6,368,419			$	6,505,098

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, 2014, Cameco met these requirements.

The terms of NUKEM’s revolving loan facility contain a financial covenant that places restrictions on total debt and working capital balances. The facility also requires Cameco, as guarantor, to maintain a minimum credit rating. As of December 31, 2014 the Company is in compliance with all requirements under this facility.

 

30.	Segmented information

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

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

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

 

54

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A. Business segments

For the year ended December 31, 2014

 

		Uranium				Fuel services				NUKEM				Other				Total
Revenue		$	1,777,180			$	306,235			$	349,245			$	(35,128	)		$	2,397,532
Expenses
Cost of products and services sold			902,813				237,872				319,369				(39,286	)			1,420,768
Depreciation and amortization			272,632				30,038				7,584				28,729				338,983
Cost of sales			1,175,445				267,910				326,953				(10,557	)			1,759,751
Gross profit (loss)			601,735				38,325				22,292				(24,571	)			637,781
Administration			—				—				16,591				159,794				176,385
Impairment charges			143,078				183,615				—				—				326,693
Exploration			46,565				—				—				—				46,565
Research and development			—				—				—				5,044				5,044
Loss (gain) on disposal of assets			32,959				11,808				(5	)			—				44,762
Finance costs			—				—				3,769				73,353				77,122
Losses on derivatives			—				—				1,799				119,361				121,160
Finance income			—				—				(14	)			(7,388	)			(7,402	)
Share of loss from equity-accounted investees			3,874				13,267				—				—				17,141
Other expense (income)			(68,626	)			18,035				—				—				(50,591	)
Earnings (loss) before income taxes			443,885				(188,400	)			152				(374,735	)			(119,098	)
Income tax recovery																			(175,268	)
Net earnings from continuing operations																		$	56,170
Capital expenditures for the year		$	466,332			$	13,776			$	—			$	—			$	480,108

 

55

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For the year ended December 31, 2013

 

		Uranium				Fuel services				NUKEM				Other				Total
Revenue		$	1,632,508			$	319,157			$	464,592			$	22,466			$	2,438,723
Expenses
Cost of products and services sold			869,137				240,746				419,771				19,584				1,549,238
Depreciation and amortization			212,881				26,241				25,459				18,175				282,756
Cost of sales			1,082,018				266,987				445,230				37,759				1,831,994
Gross profit (loss)			550,490				52,170				19,362				(15,293	)			606,729
Administration			—				—				15,240				169,736				184,976
Impairment charge			70,159				—				—				—				70,159
Exploration			72,833				—				—				—				72,833
Research and development			—				—				—				7,302				7,302
Loss on disposal of assets			6,766				—				—				—				6,766
Finance costs			—				—				7,936				54,185				62,121
Losses (gains) on derivatives			—				—				(10,215	)			72,185				61,970
Finance income			—				—				(69	)			(6,898	)			(6,967	)
Share of loss from equity-accounted investees			1,033				13,074				—				—				14,107
Other expense			16,587				—				—				1,739				18,326
Earnings (loss) before income taxes			383,112				39,096				6,470				(313,542	)			115,136
Income tax recovery																			(117,230	)
Net earnings from continuing operations																		$	232,366
Capital expenditures for the year		$	635,152			$	10,499			$	133,924			$	—			$	779,575

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:

 

		2014				2013
Canada		$	308,327			$	230,505
Germany			174,622				232,296
United States			1,914,583				1,975,922
		$	2,397,532			$	2,438,723

 

56

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

 

		2014				2013
Canada		$	4,048,009			$	3,868,871
United States			409,495				371,705
Germany			116,106				105,293
Australia			643,986				645,952
Other			274,527				243,203
		$	5,492,123			$	5,235,024

31. Group entities

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

 

		Principal place				Ownership interest
		of business				2014				2013
Subsidiaries:
Cameco Bruce Holdings Inc.			Canada				—				100	%
Cameco Bruce Holdings II Inc.			Canada				—				100	%
Cameco Fuel Manufacturing Inc.			Canada				100	%			100	%
Cameco Inc.			US				100	%			100	%
Power Resources, Inc.			US				100	%			100	%
Crow Butte Resources, Inc.			US				100	%			100	%
Urtek LLC			US				73	%			73	%
NUKEM Investments GmbH			Germany				100	%			100	%
Cameco Australia Pty. Ltd.			Australia				100	%			100	%
Cameco Europe Ltd.			Switzerland				100	%			100	%
Associates
GE-Hitachi Global Laser Enrichment LLC			US				24.00	%			24.00	%
UEX Corporation			Canada				21.28	%			21.95	%

32. Joint operations

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

 

57

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

 

		Principle place of business				Ownership				2014				2013
Total assets
McArthur River			Canada				69.81	%		$	1,074,501			$	1,034,095
Key Lake			Canada				83.33	%			645,186				626,090
Cigar Lake			Canada				50.03	%			1,617,101				1,370,476
Inkai			Kazakhstan				60.00	%			359,554				323,404
										$	3,696,342			$	3,354,065
Total liabilities
McArthur River							69.81	%		$	54,170			$	51,094
Key Lake							83.33	%			181,443				149,263
Cigar Lake							50.03	%			52,580				55,718
Inkai							60.00	%			171,198				170,134
										$	459,391			$	426,209

Through unsecured shareholder loans, Cameco has agreed to fund the development of the Inkai project. Cameco eliminates the loan balances recorded by Inkai and records advances receivable (notes 12 and 33) representing its 40% ownership interest.

33. 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 27). Senior management and directors also participate in the Company’s share-based compensation plans (note 26).

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.

 

58

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Compensation for key management personnel was comprised of:

 

		2014				2013
Short-term employee benefits		$	19,922			$	21,276
Post-employment benefits			8,395				4,415
Share-based compensation (a)			11,306				11,864
		$	39,623			$	37,555

 

(a)	Excludes deferred share units held by directors (see note 26).

Other related party transactions

 

		Transaction value year ended								Balance outstanding as at
		2014				2013				2014				2013
Joint arrangements
Interest income (Inkai)(a)		$	2,038			$	2,053			$	91,672			$	95,319
Associates
Interest expense			(5	)			(220	)			—				(10,647	)

 

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

Through unsecured shareholder loans, Cameco has agreed to fund Inkai’s project development costs as well as further evaluation on block 3. The limits of the loan facilities are $244,650,000 (US) and advances under these facilities bear interest at a rate of LIBOR plus 2%. At December 31, 2014, $197,551,000 (US) of principal and interest was outstanding (2013 - $224,047,000 (US)).

In 2008, a promissory note in the amount of $73,344,000 (US) was issued to finance the acquisition of GLE. No balance was outstanding under this promissory note at December 31, 2014. At December 31, 2013, $10,010,000 (US) of principal and interest was outstanding.

34. Subsequent event

On January 21, 2015, Cameco received a Notice of Proposed Assessment (NOPA) from the United States Internal Revenue Service (IRS) pertaining to its 2009 taxation year. A NOPA is used by the IRS to communicate a proposed adjustment to income and is subject to negotiation and change; it is not the final tax assessment. The NOPA provides the basis for the IRS to issue a Revenue Agent Report (RAR), which lists the proposed adjustments and calculates tax and any penalties owing based on the proposed adjustments. We currently anticipate receiving a final RAR in the first quarter of 2015.

The NOPA we received is focused on the transfer pricing used for certain intercompany transactions within our corporate structure. The IRS has proposed that a portion of the non-US income reported under our corporate structure and taxed in non-US jurisdictions should be recognized and taxed in the US. We believe that the conclusions of the IRS in the NOPA are incorrect and are contesting them. We believe that the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

 

59

EXHIBIT 99.3

Cameco Corporation

2014 Management’s Discussion and Analysis

February 9, 2015

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Management’s discussion and analysis

February 9, 2015

 

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

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our audited consolidated financial statements (financial statements) and notes for the year ended December 31, 2014. The information is based on what we knew as of February 5, 2015.

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

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

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

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

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Caution about forward-looking information

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

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

 

•

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

 

•

It represents our current views, and can change significantly.

 

•

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

 

•

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

 

•

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

Examples of forward-looking information in this MD&A

 

 

Material risks

 

 

2    CAMECO CORPORATION

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Material assumptions

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    3

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4    CAMECO CORPORATION

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MANAGEMENT’S DISCUSSION AND ANALYSIS    5

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2014 performance highlights

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

Strong financial performance

Our financial results remained strong in 2014:

 

•

annual revenue of $2.4 billion

 

•

annual gross profit of $638 million

 

•

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

 

•

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

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

partially offset by:

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

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

 

6    CAMECO CORPORATION

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Solid progress in our uranium segment this year

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

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

Updates on our other segments and investments

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

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    7

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

 

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

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

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

 

 

8    CAMECO CORPORATION

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Market overview

The world needs energy

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

 

Nuclear – an integral part of the energy mix

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

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

Reactors – gigawatt growth

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

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    9

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

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

 

More reactors means more demand for uranium

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

Can supply keep up?

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

 

 

10    CAMECO CORPORATION

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

 

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

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

Today – little demand, a lot of supply

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    11

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2014 market developments

SUPPLY AND DEMAND

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

CONTRACTING

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

 

JAPAN

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

OTHER REGIONS

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

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

 

12    CAMECO CORPORATION

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Industry prices

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

 

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

 

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

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    13

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Our strategy

Positioned for success

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

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

URANIUM

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

FUEL SERVICES

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

ENRICHMENT

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

NUKEM

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

Our mission is to energize

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

 

 

14    CAMECO CORPORATION

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Capital allocation – focus on value

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

 

•

create the greatest long-term value for our shareholders

 

•

allow us to maintain our investment grade rating

 

•

ensure we execute on our dividend policy

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

REINVESTMENT

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

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

RETURN

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

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

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

Marketing strategy – balanced contract portfolio

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

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    15

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OPTIMIZING REALIZED PRICE

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

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

LONG-TERM CONTRACTING

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

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

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

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

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

CONTRACT PORTFOLIO STATUS

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

Customers – U₃O₈:

Five largest customers account for 50% of commitments

 

 

16    CAMECO CORPORATION

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Customers – UF₆ conversion:

 

•

Five largest customers account for 56% of commitments

 

MANAGING OUR CONTRACT COMMITMENTS

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

 

•

from our existing production

 

•

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

 

•

from our existing inventory

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

 

•

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

 

•

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

 

•

purchases under existing and/or new arrangements

 

•

discretionary use of inventories

 

•

market opportunities

Focusing on cost efficiency

PRODUCTION COSTS

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

 

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    17

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

PURCHASES AND INVENTORY COSTS

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

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

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

FINANCIAL IMPACT

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

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

Sustainable development: A key part of our strategy

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

 

•

build trust, credibility and corporate reputation

 

•

gain and enhance community support for our operations and plans

 

•

attract and retain employees

 

•

manage risk

 

•

drive innovation and continual improvement to build competitive advantage

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

SAFE, HEALTHY, REWARDING WORKPLACE

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

2014 Highlights:

 

•

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

 

•

continued low average dose of radiation to workers

 

•

won John T Ryan National Safety award for McArthur River mine

 

•

top employer awards

A CLEAN ENVIRONMENT

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

 

18    CAMECO CORPORATION

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

2014 Highlights:

 

•

decrease in treated water discharged to surface water

 

•

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

SUPPORTIVE COMMUNITIES

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

2014 Highlights:

 

•

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

 

•

794 local employees from northern Saskatchewan

 

•

no significant disputes related to land use or customary rights

 

•

community engagement activities at 100% of our operations

OUTSTANDING FINANCIAL PERFORMANCE

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

2014 Highlights:

 

•

continue to achieve an average realized price that outperforms the market

 

•

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

MONITORING AND MEASUREMENT

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

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

 

•

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

 

•

we have participated in the Carbon Disclosure Project since 2006

Achievements

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    19

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Measuring our results

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

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

 

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

 

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

 

20    CAMECO CORPORATION

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2015 objectives

OUTSTANDING FINANCIAL PERFORMANCE

 

•

Achieve targeted adjusted net earnings and cash flow from operations.

 

•

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

SAFE, HEALTHY AND REWARDING WORKPLACE

 

•

Improve workplace safety performance at all sites.

 

•

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

CLEAN ENVIRONMENT

 

•

Improve environmental performance at all sites.

SUPPORTIVE COMMUNITIES

 

•

Build and sustain strong stakeholder support for our activities.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    21

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Financial results

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

 

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

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2014 consolidated financial results

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

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

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

 

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

Net earnings

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

partially offset by:

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

THREE-YEAR TREND

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    23

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

Impairment charge on producing assets

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

Non-IFRS measures

ADJUSTED NET EARNINGS

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

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

To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the years ended 2014, 2013 and 2012.

 

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

 

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

 

24    CAMECO CORPORATION

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

 

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

THREE-YEAR TREND

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

The 3% increase from 2012 to 2013 resulted from:

 

•

addition of gross profit from NUKEM

 

•

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

 

•

lower income taxes

partially offset by:

 

•

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

The 7% decrease from 2013 to 2014 resulted from:

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

partially offset by:

 

•

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

 

•

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

 

•

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    25

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Revenue

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

 

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

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

THREE-YEAR TREND

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

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

OUTLOOK FOR 2015

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

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns and, therefore, our sales volumes and revenue, can vary significantly. We expect the quarterly distribution of uranium deliveries to be relatively balanced in 2015. However, not all delivery notices have been received to date, which could alter the delivery pattern. Typically, we receive notices six months in advance of the requested delivery date.

Average realized prices

 

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

 

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

Discontinued operation

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

 

26    CAMECO CORPORATION

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

Corporate expenses

ADMINISTRATION

 

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

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

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

Outlook for 2015

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

EXPLORATION

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

Outlook for 2015

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

FINANCE COSTS

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

FINANCE INCOME

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

GAINS AND LOSSES ON DERIVATIVES

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

INCOME TAXES

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    27

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

 

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

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

2	Our IFRS-based measures have been adjusted by the amounts reflected in the table in adjusted net earnings (non-IFRS measure on page 24).

TRANSFER PRICING DISPUTES

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

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

 

•

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

 

•

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

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

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

 

28    CAMECO CORPORATION

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CRA dispute

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

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

 

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

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

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

 

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

 

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

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    29

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IRS dispute

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

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

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

 

•

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

 

•

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

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

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

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

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

Overview of disputes

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

 

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

 

30    CAMECO CORPORATION

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

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

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

 

 

OUTLOOK FOR 2015

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

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

FOREIGN EXCHANGE

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

Sales of uranium and fuel services are routinely denominated in US dollars, while production costs are largely denominated in Canadian dollars. We use planned hedging to try to protect net inflows (total sales less US dollar cash expenses and product purchases) against declines in the US dollar in the shorter term. Our strategy is to hedge net inflows over a rolling 60-month period. Our policy is to hedge 35% to 100% of net inflows in the first 12 months. The range declines every year until it reaches 0% to 10% of our net inflows (from 49 and 60 months).

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    31

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At December 31, 2014:

 

•

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

 

•

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

 

•

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

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2014, all counterparties to foreign exchange hedging contracts had a Standard & Poor’s (S&P) credit rating of A or better.

SENSITIVITY ANALYSIS

At December 31, 2014, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2015 net earnings by about $7 million (Cdn), with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact. This sensitivity is based on an exchange rate of $1.00 (US) for $1.00 (Cdn).

Outlook for 2015

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

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

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

2015 FINANCIAL OUTLOOK

 

CONSOLIDATED

URANIUM1

FUEL SERVICES

NUKEM1

Production

—

25.3 to 26.3 million lbs

9 to 10 million kgU

—

Sales volume1

—

31 to 33 million lbs

Decrease 5% to 10%

7 to 8 million lbs U3O8

Revenue compared to 20142

Decrease 0% to 5%

Decrease 5% to 10%

3

Decrease 0% to 5%

Increase 5% to 10%

Average unit cost of sales (including D&A)

—

Increase 5% to 10%

4

Increase 5% to 10%

Increase 0% to 5%

Direct administration costs compared to 20145

Increase 0% to 5%

—

—

Decrease 0% to 5%

Exploration costs compared to 2014

—

Decrease 5% to 10%

—

—

Tax rate

Recovery of 60% to 65%

—

—

Expense of 30% to 35%

Capital expenditures

$370 million

—

—

—

 

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

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

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

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

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

 

32    CAMECO CORPORATION

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REVENUE AND EARNINGS SENSITIVITY ANALYSIS

For 2015, a change of $5 (US) per pound in each of the Ux spot price ($37.50 (US) per pound on February 2, 2015) and the Ux long-term price indicator ($49.00 (US) per pound on January 26, 2015) would change revenue by $93 million and net earnings by $55 million.

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

The table below and graph on the following page are not forecasts of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table and graph. They are designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2014 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on December 31, 2014, and none of the assumptions we list below change.

We intend to update this table and graph each quarter in our MD&A to reflect deliveries made and changes to our contract portfolio. As a result, we expect the table and graph to change from quarter to quarter.

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)

 

SPOT PRICES ($US/lb U3O8)		$20				$40				$60				$80				$100				$120				$140
2015			41				46				55				63				72				80				87
2016			41				47				57				68				78				87				95
2017			41				46				57				67				78				87				94
2018			42				48				58				69				79				87				93
2019			43				49				59				69				78				85				91

 

 

The table and graph illustrate the mix of long-term contracts in our December 31, 2014 portfolio, and are consistent with our marketing strategy. Both have been updated to reflect deliveries made and contracts entered into up to December 31, 2014.

Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. Those that are fixed at lower prices or have low ceiling prices will yield prices that are lower than current market prices.

 

Our portfolio is affected by more than just the spot price. We made the following assumptions (which are not forecasts) to create the table:

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    33

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Liquidity and capital resources

At the end of 2014, we had cash and short-term investments of $567 million in a mix of short-term deposits and treasury bills, while our total debt amounted to $1.5 billion.

We have large, creditworthy customers that continue to need uranium even during weak economic conditions, and we expect the uranium contract portfolio we have built to provide a solid revenue stream for years to come.

We expect to continue investing in maintaining and prudently expanding our production capacity over the next several years. We have a number of alternatives to fund future capital requirements, including using our current cash balances, drawing on our existing credit facilities, entering new credit facilities, using our operating cash flow, and raising additional capital through debt or equity financings. We are always considering our financing options so we can take advantage of favourable market conditions when they arise. However, we expect our cash balances and operating cash flows will meet our anticipated 2015 capital requirements without the need for significant additional funding.

We have an ongoing dispute with CRA regarding our offshore marketing company structure and related transfer pricing arrangements. See page 27 for more information. Until this dispute is settled, we expect to make remittances for future amounts owing to the Government of Canada for 50% of the cash taxes payable and the related interest and penalties. We have provided an estimate of the amount and timing of the expected cash taxes and transfer pricing penalties paid or owing in the table on page 27.

FINANCIAL CONDITION

 

		2014				2013
Cash position ($ millions) (cash, cash equivalents, short-term investments, less bank overdraft)			567				188
Cash provided by continuing operations ($ millions) (net cash flow generated by our operating activities after changes in working capital)			480				524
Cash provided by operations/net debt (net debt is total consolidated debt, less cash position)			52	%			45	%
Net debt/total capitalization (total capitalization is total long-term debt and equity)			13	%			17	%

CREDIT RATINGS

The credit ratings assigned to our securities by external ratings agencies are important to our ability to raise capital at competitive pricing to support our business operations. Our investment grade credit ratings reflect the current financial strength of our company.

Third-party ratings for our commercial paper and senior debt as of December 31, 2014:

 

SECURITY		DBRS		S&P
Commercial paper		R-1 (low)			A-1 (low)1
Senior unsecured debentures		A (low)			BBB+
Rating trend / rating outlook		Stable			Negative

 

1	Canadian National Scale Rating. The Global Scale Rating is A-2.

 

34    CAMECO CORPORATION

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DBRS provides guidance for the outlook of the assigned rating using the rating trend. The rating trend represents their assessment of the likelihood and direction that the rating could change in the future, should present tendencies continue, or in some cases, if challenges are not overcome.

S&P uses rating outlooks to assess the potential direction of a long-term credit rating over the intermediate term. Their outlook indicates the likelihood that the rating could change in the future.

The rating agencies may revise or withdraw these ratings if they believe circumstances warrant. A change in our credit ratings could affect our cost of funding and our access to capital through the capital markets.

Liquidity

 

($ MILLIONS)		2014				2013
Cash, cash equivalents and short-term investments at beginning of year			188				799
Cash from operations			480				530
Investment activities
Additions to property, plant and equipment and acquisitions			(480	)			(898	)
Discontinued operation			447				—
Other investing activities			12				(6	)
Financing activities
Change in debt			146				(18	)
Interest paid			(78	)			(66	)
Contributions from non-controlling interest			1				—
Issue of shares			6				2
Dividends			(158	)			(158	)
Exchange rate on changes on foreign currency cash balances			3				3
Cash, cash equivalents and short-term investments, less bank overdraft at end of year			567				188

CASH FROM CONTINUING OPERATIONS

Cash from continuing operations was 8% lower than in 2013 mainly due to higher payments related to our CRA litigation, offset by working capital requirements and higher profits in the uranium business. Not including working capital requirements, our operating cash flows in the year were down $96 million. See note 25 to the financial statements.

INVESTING ACTIVITIES

Cash used in investing includes acquisitions and capital spending.

Acquisitions and divestitures

On January 30, 2014, we signed an agreement with BPC Generation Infrastructure Trust to sell our 31.6% limited partnership interest in BPLP and related entities for $450 million. The effective date for the sale is January 1, 2014. We have realized an after tax gain of $127 million on this divestiture.

Capital spending

We classify capital spending as sustaining, capacity replacement or growth. As a mining company, sustaining capital is the money we spend to keep our facilities running in their present state, which would follow a gradually decreasing production curve, while capacity replacement capital is spent to maintain current production levels at those operations. Growth capital is money we invest to generate incremental production, and for business development.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    35

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CAMECO’S SHARE ($ MILLIONS)		2014 PLAN				2014 ACTUAL				2015 PLAN
Sustaining capital
McArthur River/Key Lake			25				22				25
Cigar Lake			25				14				15
Rabbit Lake			45				33				35
US ISR			5				3				5
Inkai			10				9				5
Fuel services			10				8				15
Other			15				6				5
Total sustaining capital			135				95				105
Capacity replacement capital
McArthur River/Key Lake			55				57				85
Cigar Lake			35				38				35
Rabbit Lake			—				—				—
US ISR			20				23				20
Inkai			15				10				15
Total capacity replacement capital			125				128				155
Growth capital
McArthur River/Key Lake			60				51				25
Cigar Lake			155				186				70
US ISR			5				2				—
Inkai			5				10				5
Fuel services			5				6				5
Other			—				2				5
Total growth capital			230				257				110
Total uranium & fuel services			490	1			480				370

 

1	Capital spending outlook was updated to $490 million in our third quarter MD&A.

Outlook for investing activities

 

(CAMECO’S SHARE IN $ MILLIONS)		2016 PLAN		2017 PLAN
Total uranium & fuel services		300-350		350-400
Sustaining capital		125-140		155-170
Capacity replacement capital		100-115		125-140
Growth capital		75-95		70-90

We expect total capital expenditures for uranium and fuel services to decrease by about 23% in 2015.

Major sustaining, capacity replacement and growth expenditures in 2015 include:

 

•

McArthur River/Key Lake – At McArthur River, the largest projects are the upgrade of the electrical infrastructure, the expansion of freeze capacity and mine development. Other projects include site facility and equipment purchases. At Key Lake, work will be completed on the calciner.

 

•

US in situ recovery (ISR) – wellfield construction represents the largest portion of our expenditures in the US.

 

•

Rabbit Lake – At Eagle Point, the largest component is mine development, along with mine equipment upgrades and purchases. Work on various mill facility and equipment replacements will also continue.

 

•

Cigar Lake – Underground mine development makes up the largest portion of capital at the Cigar Lake site. We are also paying our share of the costs to modify and expand the McClean Lake mill.

We previously expected to spend between $400 million and $450 million in 2015, and between $500 million and $550 million in 2016. We now expect to spend $370 million in 2015 and between $300 million and $350 million in 2016. The change is due to the removal of our fixed production target and the decrease in spending on the related projects. As the market begins to signal new production is needed, we plan to increase our capital expenditures to allow us to be among the first to respond to the growth we see coming.

This information regarding currently expected capital expenditures for future periods is forward-looking information, and is based upon the assumptions and subject to the material risks discussed on pages 2 and 3. Our actual capital expenditures for future periods may be significantly different.

 

36    CAMECO CORPORATION

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FINANCING ACTIVITIES

Cash from financing includes borrowing and repaying debt, and other financial transactions including paying dividends and providing financial assurance.

Long-term contractual obligations

 

DECEMBER 31 ($ MILLIONS)		2015				2016 AND 2017				2018 AND 2019				2020 AND BEYOND				TOTAL
Long-term debt			—				—				500				1,000				1,500
Interest on long-term debt			69				139				139				267				614
Provision for reclamation			19				60				75				720				874
Provision for waste disposal			2				9				5				2				18
Other liabilities			—				—				—				62				62
Capital commitments			99				—				—				—				99
Total			189				208				719				2,051				3,167

We have contractual capital commitments of approximately $99 million at December 31, 2014. Certain of the contractual commitments may contain cancellation clauses; however, we disclose the commitments based on management’s intent to fulfill the contracts. The majority of the $99 million is expected to be incurred in 2015.

We have unsecured lines of credit of about $2.4 billion, which include the following:

 

•

A $1.25 billion unsecured revolving credit facility that matures November 1, 2018. Each year on the anniversary date, and upon mutual agreement, the facility can be extended for an additional year. In addition to borrowing directly from this facility, we can use up to $100 million of it to issue letters of credit and we may use it to provide liquidity for our commercial paper program, as necessary. We may increase the revolving credit facility above $1.25 billion, by increments of no less than $50 million, up to a total of $1.75 billion. The facility ranks equally with all of our other senior debt. At December 31, 2014, there were no amounts outstanding under this facility.

 

•

Approximately $951 million in short-term borrowing and letters of credit provided by various financial institutions. We use these facilities mainly to provide financial assurance for future decommissioning and reclamation of our operating sites, and as overdraft protection. At December 31, 2014, we had approximately $942 million outstanding in letters of credit.

In the second quarter of 2014, we issued $500 million in Series G debentures bearing interest at 4.19% per year, maturing on June 24, 2024. On July 16, 2014, we redeemed Series C debentures in aggregate principal amount of $300 million.

In total, considering the early redemption of the Series C debentures, we have $1.5 billion in senior unsecured debentures outstanding:

 

•

$500 million bearing interest at 5.67% per year, maturing on September 2, 2019

 

•

$400 million bearing interest at 3.75% per year, maturing on November 14, 2022

 

•

$500 million bearing interest at 4.19% per year, maturing on June 24, 2024

 

•

$100 million bearing interest at 5.09% per year, maturing on November 14, 2042

The $73 million (US) promissory note we issued to GLE to support future development of its business has been fully drawn and no obligation is outstanding.

Debt covenants

Our revolving credit facility includes the following financial covenants:

 

•

our funded debt to tangible net worth ratio must be 1:1 or less

 

•

other customary covenants and events of default

Funded debt is total consolidated debt less the following: non-recourse debt, $100 million in letters of credit, cash and short-term investments.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    37

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Not complying with any of these covenants could result in accelerated payment and termination of our revolving credit facility. At December 31, 2014, we complied with all covenants, and we expect to continue to comply in 2015.

Nukem financing arrangement

NUKEM enters into financing arrangements with third parties where future receivables arising from certain sales contracts are sold to financial institutions in exchange for cash. These arrangements require NUKEM to satisfy its delivery obligations under the sales contracts, which are recognized as deferred sales (see notes 9 and 17 to the financial statements for more information). In some of the arrangements, NUKEM is also required to pledge the underlying inventory as security against these performance obligations. As of December 31, 2014, NUKEM had $64.7 million (US) of inventory pledged as security under financing arrangements, compared with $31.8 million (US) at December 31, 2013.

OFF-BALANCE SHEET ARRANGEMENTS

We had two kinds of off-balance sheet arrangements at the end of 2014:

 

•

purchase commitments

 

•

financial assurances

Purchase commitments

The table below is based on our purchase commitments at December 31, 2014. These commitments include a mix of fixed price and market-related contracts. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of purchase. We will update this table as required in our MD&A to reflect changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.

 

DECEMBER 31 ($ MILLIONS)		2015				2016 AND 2017				2018 AND 2019				2020 AND BEYOND				TOTAL
Purchase commitments1			733				648				285				502				2,168

 

1	Denominated in US dollars, converted to Canadian dollars as of December 31, 2014 at the rate of $1.16.

At the end of 2014, we had committed to $2.2 billion (Cdn) for the following:

 

•

approximately 35 million pounds of U3O8 equivalent from 2015 to 2028

 

•

approximately 4 million kgU as UF6 in conversion services from 2015 to 2018

 

•

about 1 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-Western supplier

The suppliers do not have the right to terminate agreements other than pursuant to customary events of default provisions.

Financial assurances

Standby letters of credit mainly provide financial assurance for the decommissioning and reclamation of our mining and conversion facilities. We are required to provide letters of credit to various regulatory agencies until decommissioning and reclamation activities are complete. Letters of credit are issued by financial institutions for a one-year term. At December 31, 2014 our financial assurances totaled $942 million compared to $849 million at December 31, 2013. The increase is mainly due to increased requirements for decommissioning letters of credit for Rabbit Lake and McArthur River, and exchange rate fluctuations. The increases were partially offset by the sale of BPLP, which eliminated our commitment for financial guarantees on its behalf. These guarantees were estimated at $58 million at the end of 2013.

 

38    CAMECO CORPORATION

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BALANCE SHEET

 

DECEMBER 31 ($ MILLIONS EXCEPT PER SHARE AMOUNTS)		2014				2013				2012				CHANGE 2013 TO 2014
Inventory			902				913				564				(1	)%
Total assets			8,473				8,039				7,431				5	%
Long-term financial liabilities			2,448				1,915				1,903				28	%
Dividends per common share			0.40				0.40				0.40				—

Total product inventories decreased by 1% to $902 million this year due to lower levels of inventory for uranium and fuel services, where the quantities sold were higher than the quantities produced and purchased for the year, partially offset by higher inventories in our NUKEM segment. In 2014, total volume of product inventories decreased by 24%; however, the average cost of uranium was higher as the cost of material produced and purchased during the year was higher than the average cost of inventory at the beginning of the year. At December 31, 2014, our average cost for uranium was $32.00 per pound, up from $29.15 per pound at December 31, 2013.

At the end of 2014, our total assets amounted to $8.5 billion, an increase of $0.5 billion compared to 2013 primarily due to higher deferred tax assets and an increase in long term receivables related to our CRA litigation. In 2013, the total asset balance increased by $0.6 billion compared to 2012 primarily due to the acquisition of NUKEM in that year.

The major components of long-term financial liabilities are long-term debt, the provision for reclamation, deferred sales and financial derivatives. In 2014, our balance increased by $0.5 billion due to the early redemption of our Series C debentures and the issuance of the Series G debentures, as well as an increase in deferred sales. In 2013, our balance did not change significantly.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    39

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2014 financial results by segment

Uranium

 

HIGHLIGHTS		2014				2013				CHANGE
Production volume (million lbs)			23.3				23.6				(1	)%
Sales volume (million lbs)			33.9	1			32.8				3	%
Average spot price ($US/lb)			33.21				38.17				(13	)%
Average long-term price ($US/lb)			46.46				54.13				(14	)%
Average realized price
($US/lb)			47.53				48.35				(2	)%
($Cdn/lb)			52.37				49.81				5	%
Average unit cost of sales ($Cdn/lb) (including D&A)			34.64				33.01				5	%
Revenue ($ millions)			1,777	1			1,633				9	%
Gross profit ($ millions)			602				550				9	%
Gross profit (%)			34				34				—

 

1	Includes sales of 1.4 million pounds and revenue of $48 million between our uranium, fuel services and NUKEM segments.

Production volumes in 2014 did not vary significantly from 2013. Lower production at McArthur River/Key Lake was offset by higher production at other sites. See Uranium – production overview on page 53 for more information.

Uranium revenues this year were up 9% compared to 2013 due to an increase in sales volumes of 3% and an increase of 5% in the Canadian dollar average realized price. Although the spot and term prices were lower than 2013, our average realized prices remained fairly constant compared to 2013, as lower market-related prices were largely offset by higher US dollar prices under fixed price contracts. The effect of foreign exchange resulted in a higher Canadian dollar average realized price than in the prior year. The realized foreign exchange rate was $1.10 compared to $1.03 in 2013. The spot price for uranium averaged $33.21 (US) per pound in 2014, a decline of 13% compared to the 2013 average price of $38.17 (US) per pound.

Total cost of sales (including D&A) also increased by 9% ($1.18 billion compared to $1.08 billion in 2013) mainly due to slightly higher sales volumes and an increase in the average unit cost of sales resulting from an increase in non-cash costs. Total non-cash costs were $273 million compared to $213 million in 2013 as a result of an increase in the average non-cash unit cost of inventory.

The net effect was a $52 million increase in gross profit for the year.

The following table shows the costs of produced and purchased uranium incurred in the reporting periods (non-IFRS measures, see below). These costs do not include selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.

 

($CDN/LB)		2014				2013				CHANGE
Produced
Cash cost			18.66				18.37				2	%
Non-cash cost			9.30				9.46				(2	)%
Total production cost			27.96				27.83				—
Quantity produced (million lbs)			23.3				23.6				(1	)%
Purchased
Cash cost			38.17				27.95				37	%
Quantity purchased (million lbs)			7.1				13.2				(46	)%
Totals
Produced and purchased costs			30.34				27.87				9	%
Quantities produced and purchased (million lbs)			30.4				36.8				(17	)%

Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. These measures do not have a standardized meaning or a consistent basis of calculation under IFRS. We use these measures in our assessment of the performance of our uranium business. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance and ability to generate cash flow.

 

40    CAMECO CORPORATION

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These measures are non-standard supplemental information and should not be considered in isolation or as a substitute for measures of performance prepared according to accounting standards. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS. Other companies may calculate these measures differently, so you may not be able to make a direct comparison to similar measures presented by other companies.

To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the years ended 2014 and 2013 as reported in our financial statements.

CASH AND TOTAL COST PER POUND RECONCILIATION

 

($ MILLIONS)		2014				2013
Cost of product sold			902.8				869.1
Add / (subtract)
Royalties			(91.2	)			(90.8	)
Standby charges			(24.8	)			(37.4	)
Other selling costs			(9.0	)			(1.4	)
Change in inventories			(71.9	)			63.1
Cash operating costs (a)			705.9				802.6
Add / (subtract)
Depreciation and amortization			272.6				212.9
Change in inventories			(56.2	)			10.1
Total operating costs (b)			922.3				1,025.6
Uranium produced and purchased (million lbs) (c)			30.4				36.8
Cash costs per pound (a ÷ c)			23.22				21.81
Total costs per pound (b ÷ c)			30.34				27.87

OUTLOOK FOR 2015

We expect to produce 25.3 million to 26.3 million pounds in 2015 and have commitments under long-term contracts to purchase approximately 2 million pounds.

Based on the contracts we have in place and not including sales between our segments, we expect to deliver between 31 million and 33 million pounds of U₃O₈ in 2015. We expect the unit cost of sales to be 5% to 10% higher than in 2014, primarily due to higher costs for produced material. As Cigar Lake ramps up to full production, the cash cost of material produced from the mine will initially be higher. If we make additional discretionary purchases in 2015 at a cost different than our other sources of supply, then we expect the overall unit cost of sales to be affected.

We expect revenue to be 5% to 10% lower than it was in 2014 as a result of an expected decrease in deliveries, not including sales between our segments, and a lower average realized price.

ROYALTIES

We pay royalties on the sale of all uranium extracted at our mines in the province of Saskatchewan. Two types of royalties are paid:

 

•

Basic royalty: calculated as 5% of gross sales of uranium, less the Saskatchewan resource credit of 0.75%.

 

•

Profit royalty: a 10% royalty is charged on profit up to and including $22.28/kg U3O8 ($10.11/lb) and a 15% royalty is charged on profit in excess of $22.28/kg U3O8. Profit is determined as revenue less certain operating, exploration, reclamation and capital costs. Both exploration and capital costs are deductible at the discretion of the producer.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    41

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During the period from 2013 to 2015, transitional rules apply whereby only 50% of capital costs are deductible. The remaining 50% is accumulated and deductible beginning in 2016. In addition, the capital allowance related to Cigar Lake under the previous system is grandfathered and deductible in 2016.

As a resource corporation in Saskatchewan, we also pay a corporate resource surcharge of 3.0% of the value of resource sales.

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

 

HIGHLIGHTS		2014				2013				CHANGE
Production volume (million kgU)			11.6				14.9				(22	)%
Sales volume (million kgU)			15.5	1			17.6	2			(12	)%
Realized price ($Cdn/kgU)			19.70				18.12				9	%
Average unit cost of sales ($Cdn/kgU) (including D&A)			17.24				15.16				14	%
Revenue ($ millions)			306	1			319	2			(4	)%
Gross profit ($ millions)			38				52				(27	)%
Gross profit (%)			12				16				(25	)%

 

1	Includes sales of 0.5 million kgU and revenue of $4 million between our uranium, fuel services and NUKEM segments.

2	Includes sales of 0.7 million kgU and revenue of $6 million between our uranium, fuel services and NUKEM segments.

Total revenue decreased by 4% due to a 12% decrease in sales volumes, partially offset by a 9% increase in the realized price.

The total cost of products and services sold (including D&A) remained relatively stable compared to 2013 at $268 million, as a 12% decrease in sales volume was offset by a 14% increase in the average unit cost of sales (including D&A).

The net effect was a $14 million decrease in gross profit.

OUTLOOK FOR 2015

In 2015, we plan to produce 9 million to 10 million kgU, and we expect sales volumes not including intersegment sales to be 5% to 10% lower than in 2014. Overall revenue is expected to decrease by up to 5% as lower sales volumes will be partially offset by an increase in the average realized price. We expect the average unit cost of sales (including D&A) to increase by 5% to 10%; therefore, overall gross profit will decrease as a result.

NUKEM

 

HIGHLIGHTS		2014				2013				CHANGE
Uranium sales (million lbs)			8.1	1			8.9	2			(9	)%
Average realized price ($Cdn/lb)			44.90				42.26				6	%
Cost of product sold (including D&A)			327				445				(27	)%
Revenue			349	1			465	2			(25	)%
Gross profit			22				20				10	%
Net earnings			(3	)			7				(143	)%
Adjustments on derivatives3			2				(3	)			167	%
NUKEM inventory write-down (reversal) (net of tax)			(4	)			10				(140	)%
Adjusted net earnings (loss)3			(5	)			14				(136	)%

 

1	Includes sales of 1.1 million pounds and revenue of $43 million between our uranium, fuel services and NUKEM segments.

2	Includes sales of 0.6 million pounds and revenue of $23 million between our uranium, fuel services and NUKEM segments.

3	Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (non-IFRS measure, see page 24).

During 2014, NUKEM delivered 8.1 million pounds of uranium, a decrease of 0.8 million pounds compared to the previous year due to weak market conditions. Revenues from NUKEM amounted to $349 million, 25% lower than in 2013 as a result of lower sales volume and a decline in the realized price amid lower market prices.

Gross profit amounted to $22 million, an increase of $2 million compared to 2013. Although sales volumes decreased, NUKEM’s gross margin increased by 10% compared to 2013 due to generally higher margin sales and a $14 million inventory write-down in 2013. On a percentage basis, gross profits were 6% in 2014 compared to 4% in the prior year.

 

42    CAMECO CORPORATION

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After administration costs, interest and income taxes, adjusted net earnings amounted to a loss of $5 million compared to earnings of $14 million in 2013 (non-IFRS measure, see page 29).

OUTLOOK FOR 2015

For 2015, NUKEM expects to deliver between 7 million and 8 million pounds of uranium, resulting in an increase in revenues not including intersegment sales, of 5% to 10% compared to 2014. NUKEM expects to incur administration costs up to 5% lower than in 2014. The effective income tax rate is expected to remain in the range of 30% to 35%.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    43

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Fourth quarter financial results

Consolidated results

 

HIGHLIGHTS		THREE MONTHS ENDED DECEMBER 31								CHANGE
($ MILLIONS EXCEPT WHERE INDICATED)		2014				2013
Revenue			889				977				(9	)%
Gross profit			251				185				36	%
Net earnings attributable to equity holders			73				64				14	%
$ per common share (basic)			0.18				0.16				13	%
$ per common share (diluted)			0.18				0.16				13	%
Adjusted net earnings (non-IFRS, see page 24)			205				150				37	%
$ per common share (adjusted and diluted)			0.52				0.38				37	%
Cash provided by continuing operations (after working capital changes)			236				163				45	%

NET EARNINGS

In the fourth quarter of 2014, our net earnings were $73 million ($0.18 per share diluted), an increase of $9 million compared to $64 million ($0.16 per share diluted) in 2013, mainly due to:

 

•

higher uranium gross profits resulting from higher average realized prices and lower average unit cost of sales

 

•

a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer

 

•

lower exploration expenditures

 

•

higher income tax recovery

partially offset by:

 

•

the impact of a $126 million write-down of our investments in the Eagle Point mine assets at Rabbit Lake

 

•

the write-off of $41 million of assets under construction as a result of changes made to the scope of a number of projects

 

•

no earnings from BPLP due to divestiture of our interest in the first quarter of 2014

 

•

higher losses on foreign exchange derivatives resulting from the weakening of the Canadian dollar

On an adjusted basis, our earnings this quarter were $205 million ($0.52 per share diluted) compared to $150 million ($0.38 per share diluted) (non-IFRS measure, see below) in the fourth quarter of 2013, mainly due to:

 

•

higher uranium gross profits due to a higher average realized price and lower average unit cost of sales

 

•

a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer

 

•

lower exploration expenditures

partially offset by:

 

•

no earnings from BPLP due to divestiture of our interest in the first quarter of 2014

 

44    CAMECO CORPORATION

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We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our financial performance from period to period. See page 24 for more information. The following table reconciles adjusted net earnings with our net earnings.

 

		THREE MONTHS ENDED DECEMBER 31
($ MILLIONS)		2014				2013
Net earnings attributable to equity holders			73				64
Adjustments
Adjustments on derivatives1			10				36
NUKEM inventory write-down (recovery)			(4	)			(3	)
Impairment charges			131				70
Write-off of assets			41				—
Income taxes on adjustments			(46	)			(17	)
Adjusted net earnings			205				150

 

1	We do not apply hedge accounting for our portfolio of foreign currency forward sales contracts. However, we have adjusted our gains or losses on derivatives to reflect what our earnings would have been had hedge accounting been in place.

ADMINISTRATION

Direct administration costs were $51 million in the quarter, $6 million higher than the same period last year due to the timing of expenditures. Stock-based compensation expenses were $3 million lower than the fourth quarter of 2013 due to a change in the compensation program. See note 26 to the financial statements.

 

		THREE MONTHS ENDED DECEMBER 31								CHANGE
($ MILLIONS)		2014				2013
Direct administration			51				45				13	%
Stock-based compensation			3				6				(50	)%
Total administration			54				51				6	%

QUARTERLY TRENDS

 

HIGHLIGHTS		2014																2013
($ MILLIONS EXCEPT PER SHARE AMOUNTS)		Q4				Q3				Q2				Q1				Q4				Q3				Q2				Q1
Revenue			889				587				502				419				977				597				421				444
Net earnings (losses) attributable to equity holders			73				(146	)			127				131				64				211				34				9
$ per common share (basic)			0.18				(0.37	)			0.32				0.33				0.16				0.53				0.09				0.02
$ per common share (diluted)			0.18				(0.37	)			0.32				0.33				0.16				0.53				0.09				0.02
Adjusted net earnings (non-IFRS, see page 24)			205				93				79				36				150				208				61				27
$ per common share (adjusted and diluted)			0.52				0.23				0.20				0.09				0.38				0.53				0.15				0.07
Earnings (losses) from continuing operations			72				(146	)			127				4				28				163				33				8
$ per common share (basic)			0.18				(0.37	)			0.32				0.01				0.07				0.41				0.08				0.02
$ per common share (diluted)			0.18				(0.37	)			0.32				0.01				0.07				0.41				0.08				0.02
Cash provided by (used in) continuing operations (after working capital changes)			236				263				(25	)			7				163				154				(33	)			241

Key things to note:

 

•

Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 68% of consolidated revenues in the fourth quarter of 2014 and 65% of consolidated revenues in the fourth quarter of 2013.

 

•

The timing of customer requirements, which tends to vary from quarter to quarter, drives revenue in the uranium and fuel services segments.

 

•

Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our results from period to period (see page 24 for more information).

 

•

Cash from operations tends to fluctuate as a result of the timing of deliveries and product purchases in our uranium and fuel services segments.

 

•

Quarterly results are not necessarily a good indication of annual results due to the variability in customer requirements noted above.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    45

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DISCONTINUED OPERATION

On March 27, 2014, we completed the sale of our 31.6% limited partnership interest in BPLP.

 

		THREE MONTHS ENDED DECEMBER 31
($ MILLIONS)		2014				2013
Share of earnings from BPLP and related entities			—				48
Tax expense			—				(12	)
Net earnings from discontinued operations			—				36

 

46    CAMECO CORPORATION

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Fourth quarter results by segment

Uranium

 

		THREE MONTHS ENDED DECEMBER 31								CHANGE
HIGHLIGHTS		2014				2013
Production volume (million lbs)			8.2				7.5				9	%
Sales volume (million lbs)			10.7	1			12.7				(16	)%
Average spot price ($US/lb)			37.13				35.03				6	%
Average long-term price ($US/lb)			48.00				50.00				(4	)%
Average realized price
($US/lb)			50.57				47.76				6	%
($Cdn/lb)			56.78				49.80				14	%
Average unit cost of sales ($Cdn/lb) (including D&A)			34.27				37.94				(10	)%
Revenue ($ millions)			606	1			631				(4	)%
Gross profit ($ millions)			240				150				60	%
Gross profit (%)			40				24				67	%

 

1	Includes sales of 0.4 million pounds and revenue of $15 million between our uranium, fuel services and NUKEM segments.

Production volumes this quarter were 9% higher compared to the fourth quarter of 2013, mainly as a result of higher production at McArthur River/Key Lake, in addition to the first production from Cigar Lake/McClean Lake. See Our operations and projects starting on page 50 for more information.

Uranium revenues were down 4% due to a 16% decrease in sales volumes, which represents normal quarterly variance in our delivery schedule, offset by a 14% increase in average realized price.

The average realized price increased by 14% compared to 2013 due to higher US dollar prices under fixed price contracts, and the effect of foreign exchange. In the fourth quarter of 2014, our realized foreign exchange rate was $1.12 compared to $1.04 in the prior year.

Total cost of sales (including D&A) decreased by 24% ($366 million compared to $481 million in 2013). This was the result of a 10% decrease in the average unit cost of sales and a 16% decrease in sales volumes.

The unit cost of sales decreased due to a decrease in the cash costs of produced material in the fourth quarter compared to the same period in 2013, as a result of increased production and timing of royalties. In addition, standby charges for the McClean Lake mill ceased in the fourth quarter, as production from Cigar Lake commenced.

The net effect was a $90 million increase in gross profit for the quarter.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    47

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The following table shows the costs of produced and purchased uranium incurred in the reporting periods (which are non-IFRS measures, see the paragraphs below the table). These costs do not include selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.

 

		THREE MONTHS ENDED DECEMBER 31								CHANGE
($/LB)		2014				2013
Produced
Cash cost			14.19				15.61				(9	)%
Non-cash cost			7.15				9.42				(24	)%
Total production cost			21.34				25.03				(15	)%
Quantity produced (million lbs)			8.2				7.5				9	%
Purchased
Cash cost			39.03				37.26				5	%
Quantity purchased (million lbs)			3.7				4.4				(16	)%
Totals
Produced and purchased costs			26.84				29.55				(9	)%
Quantities produced and purchased (million lbs)			11.9				11.9				—

Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. These measures do not have a standardized meaning or a consistent basis of calculation under IFRS. We use these measures in our assessment of the performance of our uranium business. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance and ability to generate cash flow.

These measures are non-standard supplemental information and should not be considered in isolation or as a substitute for measures of performance prepared according to accounting standards. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS. Other companies may calculate these measures differently, so you may not be able to make a direct comparison to similar measures presented by other companies.

To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the fourth quarters of 2014 and 2013.

CASH AND TOTAL COST PER POUND RECONCILIATION

 

		THREE MONTHS ENDED DECEMBER 31
($ MILLIONS)		2014				2013
Cost of product sold			269.0				359.8
Add / (subtract)
Royalties			(34.5	)			(52.5	)
Standby charges			—				(11.1	)
Other selling costs			(2.3	)			(4.8	)
Change in inventories			28.5				(10.3	)
Cash operating costs (a)			260.7				281.1
Add / (subtract)
Depreciation and amortization			96.7				121.2
Change in inventories			(38.0	)			(50.7	)
Total operating costs (b)			319.4				351.6
Uranium produced & purchased (million lbs) (c)			11.9				11.9
Cash costs ($/lb) (a ÷ c)			21.91				23.62
Total costs ($/lb) (b ÷ c)			26.84				29.55

 

48    CAMECO CORPORATION

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Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

 

		THREE MONTHS ENDED DECEMBER 31								CHANGE
HIGHLIGHTS		2014				2013
Production volume (million kgU)			2.7				2.7				—
Sales volume (million kgU)			7.4	1			6.5				14	%
Average realized price ($Cdn/kgU)			16.92				17.24				(2	)%
Average unit cost of sales ($Cdn/kgU) (including D&A)			14.78				14.42				2	%
Revenue ($ millions)			125	1			112				12	%
Gross profit ($ millions)			16				18				(11	)%
Gross profit (%)			13				16				(19	)%

 

1	Includes sales of 0.5 million kgU and revenue of $4 million between our uranium, fuel services and NUKEM segments.

Total revenue increased by 12% due to a 14% increase in sales volumes, partially offset by a 2% decrease in average realized price.

The total cost of sales (including D&A) increased by 17% ($109 million compared to $93 million in the fourth quarter of 2013) mainly due to a 14% increase in sales volumes and a 2% increase in the average unit cost of sales.

The net effect was a $2 million decrease in gross profit.

NUKEM

 

		THREE MONTHS ENDED DECEMBER 31								CHANGE
HIGHLIGHTS		2014				2013
Uranium sales (million lbs)			3.4	1			3.3				3	%
Average realized price ($Cdn/lb)			52.12				41.84				25	%
Cost of product sold (including D&A)			156				169				(8	)%
Revenue			159	1			188				(15	)%
Gross profit			3				19				(84	)%
Net earnings			(6	)			13				(146	)%
Adjustments on derivatives2			—				(1	)			100	%
NUKEM inventory write-down (reversal) (net of tax)			(2	)			(1	)			(100	)%
Adjusted net earnings (loss)2			(8	)			11				(173	)%

 

1	Includes sales of 1.1 million pounds and revenue of $43 million between our uranium, fuel services and NUKEM segments.

2	Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (non-IFRS measure, see page 24).

During the three months ended December 31, 2014, NUKEM delivered 3.4 million pounds of uranium, an increase of 0.1 million pounds compared to 2013 due to timing of customer requirements. NUKEM revenues amounted to $159 million compared to $188 million in 2013 due to a decline in the uranium spot price relative to the previous year.

The unit cost of uranium sold was lower in 2014 as a result of the decline in the spot price.

The net effect was a $16 million decrease in gross profit. On a percentage basis, gross profits were 2% in the fourth quarter of 2014 compared to 10% in the same period in 2013.

Administration costs were higher in the fourth quarter due to the timing of expenditures. In addition, the sale of inventory on hand at the time of the acquisition of NUKEM resulted in an allocation of the historic purchase price to the sale of uranium in the quarter. This resulted in an adjusted net loss for the fourth quarter of 2014 of $8 million, compared to earnings of $11 million (non-IFRS measure, see page 24) in 2013.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    49

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Our operations and projects

This section of our MD&A is an overview of each of our operations, what we accomplished this year, our plans for the future and how we manage risk.

 

53		URANIUM – PRODUCTION OVERVIEW
53		PRODUCTION OUTLOOK
54		URANIUM – OPERATING PROPERTIES
54		MCARTHUR RIVER MINE / KEY LAKE MILL
59		CIGAR LAKE
64		INKAI
67		RABBIT LAKE
69		SMITH RANCH-HIGHLAND
70		CROW BUTTE
71		URANIUM – PROJECTS UNDER EVALUATION
71		MILLENNIUM
71		YEELIRRIE
72		KINTYRE
73		URANIUM – EXPLORATION AND CORPORATE DEVELOPMENT
75		FUEL SERVICES
75		BLIND RIVER REFINERY
76		PORT HOPE CONVERSION SERVICES
76		CAMECO FUEL MANUFACTURING INC. (CFM)
78		NUKEM GMBH

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Managing the risks

The nature of our operations means we face many potential risks and hazards that could have a significant impact on our business. Our risk policy and process involves a broad, systematic approach to identifying, assessing, reporting and managing the significant risks we face in our business and operations. The policy establishes clear accountabilities for enterprise risk management. We use a common risk matrix throughout the company and consider any risk that has the potential to significantly affect our ability to achieve our corporate objectives or strategic plan as an enterprise risk. However, there is no assurance we will be successful in preventing the harm any of these risks and hazards could cause. We recommend you read our most recent management proxy circular for more information about our risk oversight.

Below we list the regulatory, environmental and operational risks that generally apply to all of our operations and projects under evaluation. We also talk about how we manage specific risks in each operation or project update. These risks could have a material impact on our business in the near term.

We recommend you also review our annual information form, which includes a discussion of other material risks that could have an impact on our business.

Regulatory risks

A significant part of our economic value depends on our ability to:

 

•

obtain and renew the licences and other approvals we need to operate, to increase production at our mines and to develop new mines. If we do not receive the regulatory approvals we need, or do not receive them at the right time, then we may have to delay, modify or cancel a project, which could increase our costs and delay or prevent us from generating revenue from the project. Regulatory review, including the review of environmental matters, is a long and complex process.

 

•

comply with the conditions in these licences and approvals. In a number of instances, our right to continue operating facilities, increase production at our mines and develop new mines depends on our compliance with these conditions.

 

•

comply with the extensive and complex laws and regulations that govern our activities, including our growth plans. Environmental legislation imposes strict standards and controls on almost every aspect of our operations and the mines we plan to develop, and is not only introducing new requirements, but also becoming more stringent. For example:

 

•

we must complete the environmental assessment process before we can begin developing a new mine or make any significant change to our operations

 

•

we may need regulatory approval to make changes to our operational processes, which can take a significant amount of time because it may require an extensive review of supporting technical information. The complexity of this process can be further compounded when regulatory approvals are required from multiple agencies.

 

•

Environment Canada has brought forward a national recovery plan for woodland caribou that has the potential to impact economic and social development in northern Saskatchewan. Additional research work is being conducted so that a determination can be made on the sustainability of the species within the region. The research could result in measures being taken to further limit habitat disturbance in order to improve the health of the woodland caribou population in northern Saskatchewan, and it could have an impact on our Saskatchewan operations and projects under evaluation.

We use significant management and financial resources to manage our regulatory risks.

Environmental risks

We have the safety, health and environmental risks associated with any mining and chemical processing company. Our uranium and fuel services segments also face unique risks associated with radiation.

Laws to protect the environment are becoming more stringent for members of the nuclear energy industry and have inter-jurisdictional aspects (both federal and provincial/state regimes are applicable). Once we have permanently stopped mining and processing activities at an operating site, we are required to decommission the site to the satisfaction of the regulators. We have developed conceptual decommissioning plans for our operating sites and use them to estimate our decommissioning costs. Regulators review our conceptual decommissioning plans on a regular basis. As the site approaches or goes into decommissioning, regulators review the detailed decommissioning plans. This can result in further regulatory process, as well as additional requirements, costs and financial assurances.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    51

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At the end of 2014, our estimate of total decommissioning and reclamation costs was $874 million. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $828 million at the end of 2014 (the present value of the $874 million). Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, our expected costs for decommissioning and reclamation for the next five years are not material.

We provide financial assurances for decommissioning and reclamation such as letters of credit to regulatory authorities, as required. We had a total of $911 million in letters of credit supporting our reclamation liabilities at the end of 2014. All of our North American operations have letters of credit in place that provide financial assurance in connection with our preliminary plans for decommissioning for the sites.

Some of the sites we own or operate have been under ongoing investigation and/or remediation and planning as a result of historic soil and groundwater conditions. For example, we are addressing issues related to historic soil and groundwater contamination at Port Hope.

We use significant management and financial resources to manage our environmental risks.

We manage environmental risks through our safety, health, environment and quality (SHEQ) management system. Our chief executive officer is responsible for ensuring that our SHEQ management system is implemented. Our board’s safety, health and environment committee also oversees how we manage our environmental risks.

In 2014, we invested:

 

•

$78 million in environmental protection, monitoring and assessment programs, or 26% less than 2013 as a result of large capital projects nearing completion

 

•

$24 million in health and safety programs, or 22% more than 2013

Spending on both environmental and safety programs is expected to increase slightly in 2015, as a result of specific capital projects that are expected to begin during the year.

Operational risks

Other operational risks and hazards include:

 

We have insurance to cover some of these risks and hazards, but not all of them, and not to the full amount of losses or liabilities that could potentially arise.

 

52    CAMECO CORPORATION

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Uranium – production overview

Production in our uranium segment this quarter was 0.7 million pounds higher compared to the fourth quarter of 2013. Production for the year was 0.3 million pounds lower than in 2013. See Uranium operating properties starting on page 54 for more information.

Uranium production

 

CAMECO’S SHARE		THREE MONTHS ENDED DECEMBER 31								YEAR ENDED DECEMBER 31
(MILLION LBS)		2014				2013				2014				2013				2014 PLAN1		2015 PLAN
McArthur River/Key Lake			4.4				4.0				13.3				14.1			12.8		13.7
Rabbit Lake			2.1				2.1				4.2				4.1			4.1		3.9
Smith Ranch-Highland			0.6				0.5				2.1				1.7			2.0		1.4
Crow Butte			0.2				0.2				0.6				0.7			0.6		0.3
Inkai			0.7				0.7				2.9				3.0			3.0		3.0
Cigar Lake			0.2				—				0.2				—			0.1 - 0.3		3.0 – 4.0
Total			8.2				7.5				23.3				23.6			22.6 – 22.8		25.3 – 26.3

 

1	We updated our initial 2014 plan for McArthur River/Key Lake (to 12.8 from 13.1 million pounds) and Cigar Lake (to between 0.1 and 0.3 from between 1.0 and 1.5 million pounds) in our Q3 MD&A.

Production Outlook

We remain focused on taking advantage of the long-term growth we see coming in our industry, while maintaining the ability to respond to market conditions as they evolve. Our strategy is to profitably produce at a pace aligned with market signals to increase long-term shareholder value.

We plan to:

 

•

ensure continued reliable, low-cost production from our flagship operation, McArthur River/Key Lake and seek to expand that production

 

•

ensure continued reliable, low-cost production at Inkai

 

•

successfully ramp up production at Cigar Lake

 

•

manage the rest of our production facilities and other sources of supply in a manner that retains the flexibility to respond to market signals and take advantage of value adding opportunities within our own portfolio and the uranium market

 

•

maintain our low-cost advantage by focusing on execution and operational excellence

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    53

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Uranium – operating properties

McArthur River mine / Key Lake mill

 

		2014 Production (our share)		Proportion of 2014 U production
		13.3M lbs
		2015 Production Outlook (our share)
		13.7M lbs
		Estimated Reserves (our share)
		241.0M lbs
		Estimated Mine Life
		2033

McArthur River is the world’s largest, high-grade uranium mine, and Key Lake is the world’s largest uranium mill.

Ore grades at the McArthur River mine are 100 times the world average, which means it can produce more than 18 million pounds per year by mining only 150 to 200 tonnes of ore per day. We are the operator of both the mine and mill.

McArthur River is one of our three material uranium properties.

 

Location		Saskatchewan, Canada
Ownership		69.805% – McArthur River 83.33% – Key Lake
End product		Uranium concentrates
ISO certification		ISO 14001 certified
Mine type		Underground
Estimated reserves (our share)		241.0 million pounds (proven and probable), average grade U3O8: 14.87%
Estimated resources (our share)		7.4 million pounds (measured and indicated), average grade U3O8: 4.24% 39.9 million pounds (inferred), average grade U3O8: 7.38%
Mining methods		Primary: raiseboring Secondary: blasthole stoping, boxhole boring
Licensed capacity		Mine: 21.0 million pounds per year Mill: 25.0 million pounds per year
Licence term		Through October, 2023
Total production:  2000 to 2014 (100% basis)           1983 to 2002		269.7 million pounds (McArthur River/Key Lake) 209.8 million pounds (Key Lake)
2014 production (our share)		13.3 million pounds (19.1 million pounds on 100% basis)
2015 production outlook (our share)		13.7 million pounds (19.6 million pounds on 100% basis)
Estimated decommissioning cost (100% basis)		$48 million – McArthur River $218 million – Key Lake

BACKGROUND

Mining methods and techniques

We use a number of innovative methods to mine the McArthur River deposit:

Ground freezing

The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. We use ground freezing to form an impermeable wall around the area being mined. This prevents water from entering the mine, and helps stabilize weak rock formations. To date, we have isolated six mining areas with freezewalls.

 

54    CAMECO CORPORATION

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Raisebore mining

Raisebore mining is an innovative non-entry approach that we adapted to meet the unique challenges at McArthur River. It involves:

 

•

drilling a series of overlapping holes through the ore zone from a raisebore chamber in waste rock above the mineralization

 

•

collecting the broken ore at the bottom of the raises using line-of-sight remote-controlled scoop trams, and transporting it to a grinding circuit

 

•

once mining is complete, filling each raisebore hole with concrete

 

•

when all the rows of raises in a chamber are complete, removing the equipment and filling the entire chamber with concrete

 

•

starting the process again with the next raisebore chamber

 

 

McArthur River currently has six areas with delineated mineral reserves and delineated mineral resources (zones 1 to 4, zone 4 south and zone B) and two additional areas with delineated mineral resources (zone A, McArthur north). We are currently mining zone 2 and zone 4.

Zone 2 has been actively mined since production began. It is divided into four panels (panels 1, 2, 3 and 5) based on the configuration of the freezewall around the ore. As the freezewall is expanded, the inner connecting freezewalls are decommissioned in order to recover the uranium that was inaccessible around the active freeze pipes. Panel 5 represents the upper portion of zone 2, overlying part of the other panels. Mining is nearing completion in panels 1, 2 and 3, and the majority of the remaining zone 2 proven mineral reserves are in panel 5.

Zone 4 is divided into three mining areas: central, north and south. We are actively mining the central area and began mining zone 4 north in the fourth quarter of 2014.

The CNSC has granted approval for the use of two secondary extraction methods: blasthole stoping and boxhole boring.

We have used the approved mining methods to successfully extract about 272 million pounds (100% basis) since we began mining in 1999. Raisebore mining is scheduled to remain the primary extraction method over the life of mine.

Boxhole boring

Boxhole boring is similar to the raisebore method, but the drilling machine is located below the mineralization, so development is not required above the mineralization. This method is currently being used at a few mines around the world, but had not been used for uranium mining prior to testing at McArthur River.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    55

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Test mining to date has identified this as a viable mining option; however, only a minor amount of ore is scheduled to be extracted using this method.

Blasthole stoping

Blasthole stoping involves establishing drill access above the mineralization and extraction access below the mineralization. The area between the upper and lower access levels (the stope) is then drilled off and blasted. The broken rock is collected on the lower level and removed by line-of-sight remote-controlled scoop trams, then transported to a grinding circuit. Once a stope is mined out, it is backfilled with concrete to maintain ground stability and allow the next stope in sequence to be mined. This mining method has been used extensively in the mining industry, including uranium mining.

Blasthole stoping is planned in areas where blast holes can be accurately drilled and small stable stopes excavated without jeopardizing the freezewall integrity. We expect this method to allow for more economic recovery of ore on the periphery of the orebody, as well as smaller, lower grade areas, and we continue to study opportunities to increase the use of blasthole stoping, which would improve cost efficiency and productivity.

Initial processing

We carry out initial processing of the extracted ore at McArthur River:

 

•

the underground circuit grinds the ore and mixes it with water to form a slurry

 

•

the slurry is pumped 680 metres to the surface and stored in one of four ore slurry holding tanks

 

•

it is blended and thickened, removing excess water

 

•

the final slurry, at an average grade of 15% U3O8, is pumped into transport truck containers and shipped to Key Lake mill on an 80 kilometre all-weather road

Water from this process, including water from underground operations, is treated on the surface. Any excess treated water is released into the environment.

2014 UPDATE

Production

Production from McArthur River/Key Lake was 19.1 million pounds; our share was 13.3 million pounds. This was 4% higher than our forecast for the year as a result of a record month of production at Key Lake in December. However, annual production was 6% lower than in 2013 due to a labour disruption that resulted in an unplanned shutdown of the operations for approximately 18 days during the third quarter of 2014.

Licensing and production capacity

In 2014, the CNSC approved the EA for the Key Lake extension, a project which involves increasing our tailings capacity and Key Lake’s nominal annual production rate. We also received approval to increase the production limit at McArthur River. The licence conditions handbooks for these operations now allow:

 

•

the Key Lake mill to produce up to 25 million pounds (100% basis) per year

 

•

the McArthur River mine to produce up to 21 million pounds (100% basis) per year

With the approved EA, and once the Key Lake extension project is complete, mill production can be increased to closely follow production from the McArthur River mine.

McArthur River production expansion

We have been working to increase our annual production rate at McArthur River to 22 million pounds (100% basis). Since, in 2014, we received approval to produce up to 21 million pounds (100% basis) per year, we decided to file an application with the CNSC to increase licensed annual production up to 25 million pounds (100% basis) to allow flexibility to match the approved Key Lake mill capacity. The application was filed in January 2015.

 

56    CAMECO CORPORATION

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In order to sustain or increase production, we must continue to successfully transition into new mine areas through mine development and investment in support infrastructure. We plan to:

 

•

obtain all the necessary regulatory approvals

 

•

expand the freeze plant and electrical distribution systems

 

•

optimize the mine ventilation system

 

•

improve our dewatering system and expand our water treatment capacity as required to mitigate capacity losses should mine development increase background water volumes

 

•

expand the concrete distribution systems and batch plant capacity

New mining areas

New mining zones and increased mine production require increased ventilation and freeze capacity. In 2014, we continued to upgrade our electrical infrastructure on surface as part of our plan to address these future needs.

Underground, we began mining in zone 4 north during the fourth quarter of 2014.

Key Lake extension project and mill revitalization

The Key Lake mill began operating in 1983 and we continue to upgrade circuits with new technology to simplify operations and improve environmental performance. As part of the upgrades, we continued to construct a new calciner circuit, and expect to begin operating with the new calciner in 2015.

The revitalization plan is expected to allow the mill to increase its annual uranium production capability to closely follow annual production rates from the McArthur River mine.

Tailings capacity

This year, the CNSC approved the Key Lake extension EA, allowing us to deposit tailings to a higher level in the Deilmann tailing management facility. We now expect to have sufficient tailings capacity to mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

Labour relations

The mine and mill experienced a labour disruption that resulted in an unplanned shutdown of the operations for approximately 18 days during the third quarter of 2014. On October 6, 2014, unionized employees at McArthur River and Key Lake accepted a new four-year contract that includes a 12% wage increase over the term of the agreement. The previous contract expired on December 31, 2013.

Exploration

In 2014, we completed the planned development advance of the underground exploration drifts and underground delineation drilling.

PLANNING FOR THE FUTURE

Production

We plan to produce 19.6 million pounds in 2015; our share is 13.7 million pounds.

Mill revitalization

In 2015, we expect to complete installation and commissioning of the new calciner.

Exploration

In 2015, we plan to continue advancing the underground exploration drifts to the southwest and northeast directions. Additional drilling is planned underground to delineate zone A and zone B, and from surface to identify additional mineral resources in the deposit.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    57

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MANAGING OUR RISKS

Production at McArthur River/Key Lake poses many challenges: control of groundwater, weak rock formations, radiation protection, water inflow, mine area transitioning, and regulatory approvals. Operational experience gained since the start of production has resulted in a significant reduction in risk.

Transition to new mining areas

In order to successfully achieve the planned production schedule, we must continue to successfully transition into new mining areas, which includes mine development and investment in critical support infrastructure.

Water inflow risk

The greatest risk is production interruption from water inflows. A 2003 water inflow resulted in a three-month suspension of production. We also had a small water inflow in 2008 that did not impact production.

The consequences of another water inflow at McArthur River would depend on its magnitude, location and timing, but could include a significant interruption or reduction in production, a material increase in costs or a loss of mineral reserves.

We take the following steps to reduce the risk of inflows, but there is no guarantee that these will be successful:

 

•

Ground freezing: Before mining, we drill freezeholes and freeze the ground to form an impermeable freezewall around the area being mined. Ground freezing reduces but does not eliminate the risk of water inflows.

 

•

Mine development: We plan for our mine development to take place away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk and apply extensive additional technical and operating controls for all higher risk development.

 

•

Pumping capacity and treatment limits: Our standard for this project is to secure pumping capacity of at least one and a half times the estimated maximum sustained inflow. We review our dewatering system and requirements at least once a year and before beginning work on any new zone.

We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum sustained inflow.

We also manage the risks listed on pages 51 to 52.

 

58    CAMECO CORPORATION

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Uranium – operating properties

Cigar Lake

 

		2014 Production (our share)		Proportion of 2014 U production
		170,000 lbs
		2015 Production Outlook (our share)
		3.0 – 4.0M lbs
		Estimated Reserves (our share)
		117.5M lbs
		Estimated Mine Life
		2028

Cigar Lake is the world’s second largest high-grade uranium deposit, with grades that are 100 times the world average. We are a 50% owner and the mine operator.

Cigar Lake is one of our three material uranium properties.

 

Location		Saskatchewan, Canada
Ownership		50.025%
End product		Uranium concentrates
Mine type		Underground
Estimated reserves (our share)		117.5 million pounds (proven and probable), average grade U3O8: 17.84%
Estimated resources (our share)		2.3 million pounds (measured and indicated), average grade U3O8: 8.84% 52.5 million pounds (inferred), average grade U3O8: 16.22%
Mining methods		Jet boring
Planned capacity		18.0 million pounds per year (our share 9.0 million pounds per year)
Licence term		Through June, 2021
Total production (our share)		0.2 million pounds
2014 production (our share)		0.2 million pounds (0.4 million pounds on 100% basis)
2015 production outlook (our share)		3.0 – 4.0 million pounds (6.0 – 8.0 million pounds on 100% basis)
Estimated decommissioning cost (100% basis )		$49 million

BACKGROUND

Development

We began developing the Cigar Lake underground mine in 2005, but development was delayed due to water inflows. In 2014, we started producing from the mine and processing of the ore began at AREVA’s McClean Lake mill. In October, 2014, the mill produced the first uranium concentrate from ore mined at the Cigar Lake operation.

Mining method and techniques

We will use a number of innovative methods and techniques to mine the Cigar Lake deposit:

Bulk freezing

The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. We will freeze the ore zone and surrounding ground in the area to be mined to prevent water from entering the mine and to help stabilize weak rock formations.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    59

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We are using a hybrid freezing approach with a combination of underground and surface freezing, and are continuing to advance our surface freeze program to support future production. Through 2014, we continued to drill freezeholes from surface, expand the surface freezing infrastructure and put the new freezeholes into operation. To manage our risks and meet our production schedule, the area being mined must meet specific ground freezing requirements before we begin jet boring.

 

 

Jet boring

After many years of test mining, we selected jet boring, a non-entry mining method, which we have developed and adapted specifically for this deposit. This method involves:

 

•

drilling a pilot hole into the frozen orebody, inserting a high pressure water jet and cutting a cavity out of the frozen ore

 

•

collecting the ore and water mixture (slurry) from the cavity and pumping it to storage (sump storage), allowing it to settle

 

•

using a clamshell, transporting the ore from the sump storage to a grinding and processing circuit, eventually loading a tanker truck with ore slurry for transport to the mill

 

•

once mining is complete, filling each cavity in the orebody with concrete

 

•

starting the process again with the next cavity

Jet boring system (JBS) process

 

 

 

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We have divided the orebody into production panels, and will have one jet boring machine operating in a panel; at least three production panels need to be frozen at one time to achieve the full production rate of 18 million pounds per year by 2018. In order to achieve our 2015 production target and continue ramping up the operation, three jet boring machines are required; all three are now on site. Later in the mine plan, we may require a fourth jet boring machine to sustain annual production of 18 million pounds.

Milling

All of Cigar Lake’s ore slurry will be processed at the McClean Lake mill, operated by AREVA. The McClean Lake mill is undergoing modifications and expansion in order to:

 

•

operate at Cigar Lake’s targeted annual production level of 18 million pounds U3O8

 

•

process and package all of Cigar Lake’s current mineral reserves

The Cigar Lake joint venture is paying for the capital costs for the modification and expansion.

2014 UPDATE

Production

Total production from Cigar Lake was 340,000 pounds; our share was 170,000 pounds.

During the year, we:

 

•

brought the Cigar Lake mine into production

 

•

began processing the ore at AREVA’s McClean Lake mill, which, in the fourth quarter, produced the first uranium concentrate from the Cigar Lake operation

 

•

continued freezing the ground from surface to ensure frozen ore is available for future production years

Costs (all showing our share)

At the time of first production in March, 2014, we had:

 

•

invested about $1.2 billion for our share of the construction costs to develop Cigar Lake

 

•

expensed about $91 million in remediation expenses

 

•

expensed about $111 million in standby costs

After production began in March, and to December 31, 2014, we spent:

 

•

$83 million on the McClean Lake mill

 

•

$16 million on standby costs, which were expensed, and ceased August 31, 2014

Additional expenditures of about $60 to $70 million will be required at McClean Lake mill in 2015 in order to continue ramping up to full production.

In addition, during the year, we spent:

 

•

$57 million on operating costs

 

•

$21 million to complete various capital projects at site

 

•

$39 million on underground development

Some of the costs were capitalized, while others were charged to inventory, depending on the nature of the activity.

We will continue to capitalize some of the costs at Cigar Lake until such time that commercial production is reached. Commercial production is reached when management determines that the mine is able to produce at a consistent or sustainably increasing level.

PLANNING FOR THE FUTURE

Production

In 2015, we expect to:

 

•

begin commercial production

 

•

have three jet boring machines operating underground

 

•

continue ramping up towards the planned full production rate of 18 million pounds (100% basis) by 2018

 

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Rampup schedule

We expect Cigar Lake to produce between 6 million and 8 million packaged pounds in 2015; our share is 3 million to 4 million pounds. Based on our operating experience and productivity during rampup, we will adjust our annual production plans as necessary to allow us to reach our full annual production rate of 18 million pounds (100% basis) by 2018.

Caution regarding forward-looking information

Our expectations and plans regarding Cigar Lake, including our expected share of 2015 production, achievement of the full annual production rate of 18 million pounds by 2018, and capital costs, are forward-looking information. They are based on the assumptions and subject to the material risks discussed on pages 2 and 3, and specifically on these assumptions and risks:

 

 

MANAGING OUR RISKS

Cigar Lake is a challenging deposit to develop and mine. These challenges include control of groundwater, weak rock formations, radiation protection, water inflow, mining method uncertainty, regulatory approvals, tailings capacity, surface and underground fires and other mining-related challenges. To reduce this risk, we are applying our operational experience and the lessons we have learned about water inflows at McArthur River and Cigar Lake.

Jet boring mining method

Although we have successfully demonstrated the jet boring mining method in trials and initial mining to date, this method has not been proven at full production and we continue with commissioning work to determine if the method is capable of achieving the designed annual production rate. Mining has been completed on a limited number of cavities that may not be representative of the deposit as a whole. As we ramp up production, there may be some technical challenges, which could affect our production plans including, but not limited to, variable or unanticipated ground conditions, ground movement and cave-ins, water inflows and variable dilution, recovery values and mining productivity. There is a risk that the rampup to full production may take longer than planned and that the full production rate may not be achieved on a sustained and consistent basis. We are confident we will be able to solve challenges that may arise, but failure to do so would have a significant impact on our business.

 

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We brought the mine into production using one jet boring machine. To reach our 2015 production target and the full production rate of 18 million pounds per year by 2018 (100% basis), our mine plan requires three jet boring machines. We currently have all three machines on site, with two in operation underground and the third expected to be in operation underground in 2015. We are assessing whether a fourth jet boring machine will be required to sustain annual production of 18 million pounds, later in the mine life.

Ground freezing

To manage our risks and meet our production schedule, the areas being mined must meet specific ground freezing requirements before we begin jet boring. We have identified greater variation of the freeze rates of different geological formations encountered in the mine, based on new information obtained through surface freeze drilling. As a mitigation measure, we have increased the site freeze capacity to facilitate the extraction of ore cavities as planned.

Mill modifications

There is a risk to our plan to achieve the full production rate of 18 million pounds per year by 2018 if AREVA is unable to complete and commission the required mill modification and expansion on schedule. We are working closely with AREVA to understand and help mitigate the risks to ensure that mine and mill production schedules are aligned.

Water inflow risk

A significant risk to development and production is from water inflows. The 2006 and 2008 water inflows were significant setbacks.

The consequences of another water inflow at Cigar Lake would depend on its magnitude, location and timing, but could include a significant delay or disruption in Cigar Lake production, a material increase in costs or a loss of mineral reserves.

We take the following steps to reduce the risk of inflows, but there is no guarantee that these will be successful:

 

•

Bulk freezing: Two of the primary challenges in mining the deposit are control of groundwater and ground support. Bulk freezing reduces but does not completely eliminate the risk of water inflows.

 

•

Mine development: We plan for our mine development to take place away from known groundwater sources whenever possible. In addition, we assess all planned mine development for relative risk and apply extensive additional technical and operating controls for all higher risk development.

 

•

Pumping capacity and treatment limits: We have pumping capacity to meet our standard for this project of at least one and a half times the estimated maximum inflow.

We believe we have sufficient pumping, water treatment and surface storage capacity to handle the estimated maximum inflow.

We also manage the risks listed on pages 51 to 52.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    63

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Uranium – operating properties

Inkai

 

		2014 Production (our share)		Proportion of 2014 U production
		2.9M lbs
		2015 Production Outlook (our share)
		3.0M lbs
		Estimated Reserves (our share)
		45.6M lbs
		Estimated Mine Life
		2030 *(based on licence term)

Inkai is a very significant uranium deposit, located in Kazakhstan. There are two production areas (blocks 1 and 2) and an exploration area (block 3). The operator is joint venture Inkai limited liability partnership, which we jointly own (60%) with Kazatomprom (40%).

Inkai is one of our three material uranium properties.

 

Location		South Kazakhstan
Ownership		60%
End product		Uranium concentrates
Certifications		BSI OHSAS 18001 ISO 14001 certified
Estimated reserves (our share)		45.6 million pounds (proven and probable), average grade U3O8: 0.07%
Estimated resources (our share)		30.0 million pounds (indicated), average grade U3O8: 0.08% 145.9 million pounds (inferred), average grade U3O8: 0.05%
Mining methods		In situ recovery (ISR)
Licensed capacity (wellfields)		5.2 million pounds per year (our share 3.0 million pounds per year)
Licence term		Block 1: 2024, Block 2: 2030
Total production: 2008 to 2014 (our share)		14.9 million pounds
2014 production (our share)		2.9 million pounds (5.1 million pounds on 100% basis)
2015 production outlook (our share)		3.0 million pounds (5.2 million pounds on 100% basis)
Estimated decommissioning cost (100% basis )		$9 million (US)

2014 UPDATE

Production

Total production from Inkai was 5.1 million pounds; our share was 2.9 million pounds. Production was 3% lower than both our forecast for the year and our production in 2013. Inkai experienced delays in bringing on new wellfields as a result of abnormally heavy snowfall and a rapid spring melt in 2014.

Project funding

We have a loan agreement with Inkai whereby we funded Inkai’s project development costs. As of December 31, 2014, there was $55 million (US) of principal outstanding on the loan. In 2014, Inkai paid $1.8 million (US) in interest on the loan and repaid $48 million (US) of principal.

Under the loan agreement, Inkai first uses cash available every year to pay accrued interest, then uses 80% of the remaining cash available for distribution to repay principal outstanding on the loan. The remaining 20% is distributed as dividends to the owners.

 

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We are also currently advancing funds for Inkai’s work on block 3. As of December 31, 2014, the block 3 loan principal amounted to $136 million (US).

Production expansion

In 2012, we entered into a binding memorandum of agreement (2012 MOA) with our joint venture partner, Kazatomprom, setting out a framework to:

 

•

increase Inkai’s annual production from blocks 1 and 2 to 10.4 million pounds (our share 5.2 million pounds) and sustain it at that level

 

•

extend the term of Inkai’s resource use contract through 2045

Kazatomprom is pursuing a strategic objective to develop uranium processing capacity in Kazakhstan to complement its leading uranium mining operations. Their primary focus is now on uranium refining, which is an intermediate step in the uranium conversion process. A Nuclear Cooperation Agreement between Canada and Kazakhstan is in place, providing the international framework necessary for applying to the two governments for the required licences and permits. We expect to pursue further expansion of production at Inkai at a pace measured to market opportunities. Discussions continue with Kazatomprom.

Block 3 exploration

In 2014, Inkai continued construction of the test leach facility and test wellfields, and advanced work on a preliminary appraisal of the mineral potential according to Kazakhstan standards.

PLANNING FOR THE FUTURE

Production

We expect total production from blocks 1 and 2 to be 5.2 million pounds in 2015; our share is 3.0 million pounds. We expect to maintain production at this level until the potential expansion under the 2012 MOA proceeds.

Block 3 exploration

In 2015, Inkai expects to complete construction of the test leach facility and continue working on a final appraisal of the mineral potential according to Kazakhstan standards.

MANAGING OUR RISKS

Supply of sulphuric acid

There were minor weather-related interruptions to sulphuric acid supply during 2014. Given the importance of sulphuric acid to Inkai’s mining operations and shortages in previous years, we closely monitor its availability. Our production may be less than forecast if there is a shortage.

Block 3 Licence Extension

Inkai is working to extend the term of its current exploration licence, which expires in July, 2015. Although a number of extensions of the licence term have been granted by Kazakh regulatory authorities in the past, there is no assurance that a further extension will be granted. Without such extension, there is a risk we could lose our rights to block 3, and a risk we will not be compensated for the funds we advanced to Inkai to fund block 3 activities.

Political risk

Kazakhstan declared itself independent in 1991 after the dissolution of the Soviet Union. Our Inkai investment and plans to increase production are subject to the risks associated with doing business in developing countries, which have significant potential for social, economic, political, legal and fiscal instability. Kazakh laws and regulations are complex and still developing and their application can be difficult to predict. To maintain and increase Inkai production, we need ongoing support, agreement and co-operation from our partner and the government.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    65

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The principal legislation governing subsoil exploration and mining activity in Kazakhstan is the Subsoil Use Law dated June 24, 2010, and amended on December 29, 2014 (new subsoil law). It replaces the Law on the Subsoil and Subsoil Use, dated January 27, 1996.

In general, Inkai’s licences are governed by the version of the subsoil law that was in effect when the licences were issued in April 1999, and new legislation applies to Inkai only if it does not worsen Inkai’s position. Changes to legislation related to national security, among other criteria, however, are exempt from the stabilization clause in the resource use contract. The Kazakh government interprets the national security exemption broadly.

With the new subsoil law, the government continues to weaken its stabilization guarantee. The government is broadly applying the national security exception to encompass security over strategic national resources.

The resource use contract contains significantly broader stabilization provisions than the new subsoil law, and these contract provisions currently apply to us.

To date, the new subsoil law has not had a significant impact on Inkai. We continue to assess the impact. See our annual information form for an overview of this change in law.

We also manage the risks listed on pages 51 to 52.

 

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Uranium – operating properties

Rabbit Lake

 

		2014 Production   4.2M lbs   2015 Production Outlook   3.9M lbs   Estimated Reserves   15.2M lbs		Proportion of 2014 U production

The Rabbit Lake operation, which opened in 1975, is the longest operating uranium production facility in North America, and the second largest uranium mill in the world.

 

Location		Saskatchewan, Canada
Ownership		100%
End product		Uranium concentrates
ISO certification		ISO 14001 certified
Mine type		Underground
Estimated reserves		15.2 million pounds (proven and probable), average grade U3O8: 0.61%
Estimated resources		22.2 million pounds (indicated), average grade U3O8: 0.75% 25.9 million pounds (inferred), average grade U3O8: 0.58%
Mining methods		Vertical blasthole stoping
Licensed capacity		Mill: maximum 16.9 million pounds per year; currently 11 million
Licence term		Through October, 2023
Total production: 1975 to 2014		198.4 million pounds
2014 production		4.2 million pounds
2015 production outlook		3.9 million pounds
Estimated decommissioning cost		$203 million

2014 UPDATE

Production

Production this year was 2% higher than both our forecast and our 2013 production as a result of planned timing of production stopes, coupled with slightly improved ore grades.

Development and production continued at Eagle Point mine. At the mill, we continued to improve performance by replacing key pieces of mill infrastructure and improving the efficiency of the mill operation schedule. The mill ran continuously for eight months and maintenance work was completed during an extended four-month summer shutdown period.

Impairment

In 2014, we recognized a $126 million impairment charge related to our Rabbit Lake operation. The impairment was due to the deferral of various projects that were related to planned production over the remaining life of the Eagle Point mine. The amount of the charge was determined as the excess of the carrying value over the recoverable amount. The recoverable amount of the mine was determined to be $29 million. See note 10 to the financial statements.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    67

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Exploration

We continued our underground drilling program to delineate resources northeast of the current mine workings, and below active mining areas. As a result, we added additional resources at Rabbit Lake. See Mineral reserves and resources on page 79 for more information.

PLANNING FOR THE FUTURE

Production

We expect to produce 3.9 million pounds in 2015.

Tailings capacity

We expect to have sufficient tailings capacity to support milling of Eagle Point ore until about 2018 (based upon expected ore tonnage and milling rates).

In 2015, we are continuing to evaluate options, including expansion of the existing Rabbit Lake In-pit Tailings Management Facility, or a possible north pit expansion to allow for tailings deposition into the future. An expansion of existing tailings capacity is required to support future mining at Eagle Point, and provide additional tailings capacity to process ore from other potential sources. Depending upon the chosen option, we may need an environmental assessment and regulatory approval to proceed with any increase in capacity.

Exploration

We plan to continue our underground drilling reserve replacement program in areas of interest east and northeast of the mine in 2015. The drilling will be carried out from underground locations.

Reclamation

As part of our multi-year site-wide reclamation plan, we spent over $0.9 million in 2014 to reclaim facilities that are no longer in use and plan to spend over $0.5 million in 2015.

MANAGING OUR RISKS

We manage the risks listed on pages 51 to 52.

 

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Uranium – operating properties

Smith Ranch-Highland & Satellite Facilities

 

		2014 Production   2.1M lbs   2015 Production Outlook   1.4M lbs   Estimated Reserves   7.7M lbs		Proportion of 2014 U production

We operate Smith Ranch and Highland as a combined operation. Each has its own processing facility, but the Smith Ranch central plant currently processes all the uranium, including uranium from satellite facilities. The Highland plant is currently idle. Together, they form the largest uranium production facility in the United States.

 

Location		Wyoming, US
Ownership		100%
End product		Uranium concentrates
ISO certification		ISO 14001 certified
Estimated reserves		Smith Ranch-Highland: 4.8 million pounds (proven and probable), average grade U3O8: 0.09% North Butte-Brown Ranch: 2.9 million pounds (proven and probable), average grade U3O8: 0.08%
Estimated resources		Smith Ranch-Highland: 21.6 million pounds (measured and indicated), average grade U3O8: 0.06% 7.9 million pounds (inferred), average grade U3O8: 0.05% North Butte-Brown Ranch 8.8 million pounds (measured and indicated), average grade U3O8: 0.07% 0.4 million pounds (inferred), average grade U3O8: 0.07%
Mining methods		In situ recovery (ISR)
Licensed capacity		Wellfields: 3 million pounds per year Processing plants: 5.5 million pounds per year, including Highland mill
Licence term		Pending renewal – see Production below
Total production: 2002 to 2014		19.7 million pounds
2014 production		2.1 million pounds
2015 production outlook		1.4 million pounds
Estimated decommissioning cost		Smith Ranch-Highland: $198 million (US) North Butte: $22 million (US)

2014 UPDATE

Production

Production this year was 5% higher than our forecast and 24% higher than 2013 production, with new mine units and the North Butte satellite contributing to production at Smith Ranch-Highland in 2014.

The regulators continue to review our licence renewal application. We are allowed to continue with all previously approved activities during the licence renewal process.

PLANNING FOR THE FUTURE

Production

In 2015, we expect to produce 1.4 million pounds. The decrease is a result of market conditions, which led us to defer some wellfield development.

MANAGING OUR RISKS

We manage the risks listed on pages 51 to 52.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    69

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Uranium – operating properties

Crow Butte

 

		2014 Production   0.6M lbs   2015 Production Outlook   0.3M lbs   Estimated Reserves   1.7M lbs		Proportion of 2014 U production

Crow Butte was discovered in 1980 and began production in 1991. It is the first uranium mine in Nebraska, and is a significant contributor to the economy of northwest Nebraska.

 

Location		Nebraska, US
Ownership		100%
End product		Uranium concentrates
ISO certification		ISO 14001 certified
Estimated reserves		1.7 million pounds (proven), average grade U3O8: 0.10%
Estimated resources		14.6 million pounds (indicated), average grade U3O8: 0.27% 2.9 million pounds (inferred), average grade U3O8: 0.12%
Mining methods		In situ recovery (ISR)
Licensed capacity (processing plants and wellfields)		2.0 million pounds per year
Licence term		Through October, 2024
Total production: 2002 to 2014		9.7 million pounds
2014 production		0.6 million pounds
2015 production outlook		0.3 million pounds
Estimated decommissioning cost		$45 million (US)

2014 UPDATE

Production

Production this year was as forecast, but 14% lower than 2013 production due to declining head grade.

The US Nuclear Regulatory Commission renewed our operating licence for Crow Butte during the fourth quarter of 2014. The new licence is valid for ten years, through October, 2024.

PLANNING FOR THE FUTURE

Production

In 2015, we expect to produce 0.3 million pounds. The head grade and overall production at Crow Butte is expected to continue to decline, as there are no new wellfields being developed under the current mine plan.

MANAGING OUR RISKS

We manage the risks listed on pages 51 to 52.

 

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Uranium – projects under evaluation

We continue to advance our projects under evaluation toward development decisions at a pace aligned with market opportunities in order to respond should the market signal a need for more uranium.

The process includes several defined decision points in the assessment and development stages. At each point, we re-evaluate the project based on current economic, competitive, social, legal, political and environmental considerations. If it continues to meet our criteria, we proceed to the next stage. This process allows us to build a pipeline of projects ready for a production decision and minimize expenditures on projects whose feasibility has not yet been determined.

 

 

Millennium

 

Location		Saskatchewan, Canada
Ownership		69.9%
End product		Uranium concentrates
Potential mine type		Underground
Estimated resources (our share)		53.0 million pounds (indicated), average grade U3O8: 2.39% 20.2 million pounds (inferred), average grade U3O8: 3.19%

BACKGROUND

The Millennium deposit was discovered in 2000, and was delineated through geophysical survey and drilling work between 2000 and 2013. In 2012, we paid $150 million to acquire AREVA’s 27.94% interest in the project, bringing our interest in the project to 69.9%. We are the operator.

2014 UPDATE

We have submitted the final environmental impact statement to regulators, and in 2014, we were expecting a decision from the CNSC on a construction and operating licence for Millennium. However, we requested an adjournment of the public hearing, as moving the process forward at this time is not justified in the current uranium price environment. Based on our current assessment of the uranium market, we do not expect the deferral of the CNSC hearing will impair our ability to quickly advance Millennium to a development decision when the market signals the need for additional production.

Yeelirrie

 

Location		Western Australia
Ownership		100%
End product		Uranium concentrates
Potential mine type		Open pit
Estimated resources		127.3 million pounds (measured and indicated), average grade U3O8: 0.16%

BACKGROUND

In 2012, we paid $430 million (US) (as well as $22 million (US) in stamp duty) to acquire the Yeelirrie uranium deposit. The deposit was discovered in 1972 and is a near-surface calcrete-style deposit that is amenable to open pit mining techniques. It is one of Australia’s largest undeveloped uranium deposits.

 

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2014 UPDATE

This year, we:

 

•

continued studies to assess the technical, environmental and financial aspects of the project

 

•

commenced environmental approvals during the fourth quarter to ensure we are able to advance the project quickly, should the market signal a need for more uranium

Kintyre

 

Location		Western Australia
Ownership		70%
End product		Uranium concentrates
Potential mine type		Open pit
Estimated resources (our share)		38.7 million pounds (indicated), average grade U3O8: 0.58% 6.7 million pounds (inferred), average grade U3O8: 0.46%

BACKGROUND

In 2008, we paid $346 million (US) to acquire a 70% interest in Kintyre. The Kintyre deposit is amenable to open pit mining techniques. In 2012, we recorded a $168 million write-down of the carrying value of our interest, due to a weakened uranium market. We are the operator.

2014 UPDATE

This year:

 

•

we carried out further exploration to test for potential satellite deposits at Kintyre and other regional exploration projects close to Kintyre, which did not produce any significant results

 

•

Western Australia’s Environmental Protection Authority recommended conditional approval of the project’s Environmental Review and Management Program; state and federal ministerial approvals are pending

MANAGING THE RISKS

For all of our projects under evaluation, we manage the risks listed on pages 51 to 52.

 

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Uranium – exploration and corporate development

Our exploration program is directed at replacing mineral reserves as they are depleted by our production, and ensuring our future growth. We have maintained an active program even during periods of weak uranium prices, which has helped us secure land with exploration and development prospects that are among the best in the world, mainly in Canada, Australia, Kazakhstan and the US. Globally, our land holdings total 1.7 million hectares (4.2 million acres). In northern Saskatchewan alone, we have direct interests in 584,000 hectares (1.4 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin. Many of our prospects are located close to our existing operations where we have established infrastructure and capacity to expand.

For properties that meet our investment criteria, we may partner with other companies through strategic alliances, equity holdings and traditional joint venture arrangements. Our leadership position and industry expertise in both exploration and corporate social responsibility make us a partner of choice.

In 2014, we continued our exploration strategy of focusing on the most prospective Canadian and Australian projects in our portfolio. Exploration is key to ensuring our long-term growth, and since 2008, we have continued to invest in exploring the land we hold.

 

2014 UPDATE

Brownfield exploration

Brownfield exploration is uranium exploration near our existing operations, and includes expenses for advanced exploration projects where uranium mineralization is being defined.

This year we spent $4.1 million on six brownfield exploration projects, $5.5 million on our projects under evaluation in Australia, and $5.0 million for resource definition at Inkai and at our US operations.

Regional exploration

We spent about $32 million on regional exploration programs (including support costs), primarily in Saskatchewan and Australia.

PLANNING FOR THE FUTURE

We plan to maintain an active uranium exploration program and continue to focus on our core projects in Saskatchewan under our long-term exploration strategy.

Brownfield exploration

In 2015, we plan to spend approximately $2.8 million on brownfield exploration in Saskatchewan and Australia. Our expenditures on projects under evaluation are expected to total $5 million.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    73

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Regional exploration

We plan to spend about $25.6 million on 23 projects in Canada and Australia, the majority of which are at drill target stage. Among the larger expenditures planned is $6.9 million on the Read Lake project, which is adjacent to McArthur River in Saskatchewan.

ACQUISITION PROGRAM

We have a dedicated team looking for acquisition opportunities within the nuclear fuel cycle that could further add to our supply, support our sales activities, and complement and enhance our business in the nuclear industry. We will invest when an opportunity is available at the right time and the right price. We strive to pursue corporate development initiatives that will leave us and our shareholders in a fundamentally stronger position.

An acquisition opportunity is never assessed in isolation. Acquisitions must compete for investment capital with our own internal growth opportunities. They are subject to our capital allocation process described on page 15. Currently, given the conditions in the uranium market, and our extensive portfolio of reserves and resources, our focus is on those projects in our portfolio that provide us with the greatest certainty in the near term.

 

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Fuel services

Refining, conversion and fuel manufacturing

We control about 20% of world UF₆ conversion capacity and are a supplier of natural UO₂. Our focus is on cost-competitiveness and operational efficiency.

Our fuel services segment is strategically important because it helps support the growth of the uranium segment. Offering a range of products and services to customers helps us broaden our business relationships and expand our uranium market share.

Blind River Refinery

 

		Licensed Capacity   24.0M kgU of UO3

Blind River is the world’s largest commercial uranium refinery, refining uranium concentrates from mines around the world into UO₃.

 

Location		Ontario, Canada
Ownership		100%
End product		UO3
ISO certification		ISO 14001 certified
Licensed capacity		24.0 million kgU as UO3 per year (subject to the completion of certain equipment upgrades)
Licence term		Through February, 2022
Estimated decommissioning cost		$39 million

2014 UPDATE

Production

Our Blind River refinery produced 8.9 million kgU of UO₃ this year, enabling our conversion business to achieve its production targets.

MANAGING OUR RISKS

We manage the risks listed on pages 51 to 52.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    75

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Port Hope Conversion Services

 

		Licensed Capacity   12.5M kgU of UF6   2.8M kgU of UO2

Port Hope is the only uranium conversion facility in Canada and a supplier of UO₂ for Canadian-made CANDU reactors.

 

Location		Ontario, Canada
Ownership		100%
End product		UF6, UO2
ISO certification		ISO 14001 certified
Licensed capacity		12.5 million kgU as UF6 per year 2.8 million kgU as UO2 per year
Licence term		Through February, 2017
Estimated decommissioning cost		$102 million

Cameco Fuel Manufacturing Inc. (CFM)

CFM produces fuel bundles and reactor components for CANDU reactors.

 

Location		Ontario, Canada
Ownership		100%
End product		CANDU fuel bundles and components
ISO certification		ISO 9001 certified, ISO 14001 certified
Licensed capacity		1.2 million kgU as UO2 as finished bundles
Licence term		Through February, 2022
Estimated decommissioning cost		$20 million

2014 UPDATE

Production

Fuel services produced 11.6 million kgU, lower than our plan at the beginning of the year and 22% lower than 2013. This was a result of a decision to decrease production in response to weak market conditions.

Port Hope conversion facility cleanup and modernization (Vision in Motion)

The Vision in Motion project entered the feasibility stage in late 2014. We will continue with the CNSC licensing process in 2015, which is required to advance the project.

Springfields toll milling agreement

In 2014, amid the continued weak market for UF₆ conversion, we paid $18 million to SFL to permit early termination of our toll-conversion agreement. Production for Cameco at the Springfields facility in the United Kingdom ceased on August 31, 2014, and the agreement ended December 31, 2014.

 

76    CAMECO CORPORATION

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PLANNING FOR THE FUTURE

Production

We have decreased our production target for 2015 to between 9 million and 10 million kgU in response to weak market conditions.

Labour Relations

The current collective bargaining agreement for our unionized employees at CFM expires on June 1, 2015. We will commence the bargaining process in early 2015.

MANAGING OUR RISKS

We also manage the risks listed on pages 51 to 52.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    77

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NUKEM GmbH

 

Offices		Alzenau, Germany (Headquarters, NUKEM GmbH) Connecticut, US (Subsidiary, NUKEM Inc.)
Ownership		100%
Activity		Trading of uranium and uranium-related products
2014 sales		8.11 million pounds U3O8
2015 forecast sales		7 to 8 million pounds U3O8

 

1	Includes sales of 1.1 million pounds and revenue of $43 million between our uranium, fuel services and NUKEM segments.

BACKGROUND

In 2013, we acquired NUKEM, one of the world’s leading traders of uranium and uranium-related products. On closing, we paid €107 million ($140 million (US)) and assumed NUKEM’s net debt of about €84 million ($111 million (US)).

NUKEM has access to contracted volumes and inventories in diverse geographic locations as well as scope for opportunistic trading of uranium and uranium-related products. This enables NUKEM to provide a wide range of solutions to its customers that may fall outside the scope of typical uranium sourcing and selling arrangements. Its trading strategy is non-speculative and seeks to match quantities and pricing structures of its long-term supply and delivery contracts, minimizing exposure to commodity price fluctuations and locking in profit margins.

NUKEM’s main customers are commercial nuclear power plants using enriched uranium fuel, typically large utilities that are either government owned, or large-scale utilities with multibillion-dollar market capitalizations and strong credit ratings. NUKEM also trades with converters, enrichers, other traders and investors.

NUKEM’s business model

NUKEM’s purchase contracts are with long-standing supply partners and its sales contracts are with blue-chip utilities which have strong credit ratings.

MANAGING OUR RISKS

NUKEM manages the risks associated with trading and brokering nuclear fuels and services. It participates in the uranium spot market, making purchases to place material in higher price contracts. There are risks associated with these spot market purchases including the risk of losses. NUKEM is also subject to counterparty risk of suppliers not meeting their delivery commitments and purchasers not paying for the product delivered. If a counterparty defaults on a payment or other obligation or becomes insolvent, this could significantly affect NUKEM’s contribution to our earnings, cash flows, financial condition or results of operations.

 

78    CAMECO CORPORATION

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Mineral reserves and resources

Our mineral reserves and resources are the foundation of our company and fundamental to our success.

We have interests in a number of uranium properties. The tables in this section show our estimates of the proven and probable reserves, measured, indicated, and inferred resources at those properties. However, only three of the properties listed in those tables are material uranium properties for us: McArthur River, Cigar Lake and Inkai.

We estimate and disclose mineral reserves and resources in five categories, using the definitions adopted by the Canadian Institute of Mining, Metallurgy and Petroleum, and in accordance with Canadian National Instrument 43-101 – Standards of Disclosure for Mineral Projects (NI 43-101), developed by the Canadian Securities Administrators. You can find out more about these categories at www.cim.org.

About mineral resources

Mineral resources do not have demonstrated economic viability, but have reasonable prospects for eventual economic extraction. They fall into three categories: measured, indicated and inferred. Our reported mineral resources are exclusive of mineral reserves.

 

•

Measured and indicated mineral resources can be estimated with sufficient confidence to allow the appropriate application of technical, economic, marketing, legal, environmental, social and governmental factors to support evaluation of the economic viability of the deposit.

 

•

measured resources: we can confirm both geological and grade continuity to support detailed mine planning.

 

•

indicated resources: we can reasonably assume geological and grade continuity to support mine planning.

 

•

Inferred mineral resources are estimated using limited information. We do not have enough confidence to evaluate their economic viability in a meaningful way. You should not assume that all or any part of an inferred mineral resource will be upgraded to an indicated or measured mineral resource but it is reasonably expected that the majority of inferred mineral resources could be upgraded to indicated mineral resources with continued exploration.

Our share of uranium in the following mineral resource tables is based on our respective ownership interests, except for Inkai which is based on our interest in potential production (57.5%), which differs from our ownership interest (60%). Mineral resources that are not mineral reserves have no demonstrated economic viability.

About mineral reserves

Mineral reserves are the economically mineable part of measured and/or indicated mineral resources demonstrated by at least a preliminary feasibility study. The reference point at which mineral reserves are defined is the point where the ore is delivered to the processing plant. Mineral reserves fall into two categories:

 

•

proven reserves: the economically mineable part of a measured resource for which at least a preliminary feasibility study demonstrates that economic extraction is justified

 

•

probable reserves: the economically mineable part of a measured and/or indicated resource for which at least a preliminary feasibility study demonstrates that economic extraction is justified

We use current geological models, an average uranium price of $70 (US) per pound U₃O₈, and current or projected operating costs and mine plans to estimate our mineral reserves, allowing for dilution and mining losses. We apply our standard data verification process for every estimate.

Our share of uranium in the mineral reserves table below is based on our respective ownership interests, except for Inkai which is based on our interest in planned production (57.5%) assuming an annual production rate of 5.2 million pounds, which differs from our ownership interest (60%).

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    79

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RESERVES, MEASURED AND INDICATED (M+I) RESOURCES, INFERRED RESOURCES (WITH CHANGE FROM 2013)

at December 31, 2014

 

Changes this year

Our share of proven and probable mineral reserves went from 443 million pounds U₃O₈ at the end of 2013 to 429 million pounds at the end of 2014. The change in reserves was mainly the result of:

 

•

production, which removed 24.5 million pounds from our mineral inventory, including first production from Cigar Lake

 

•

additional drilling information at Cigar Lake from surface freezeholes

Measured and indicated mineral resources decreased from 391 million pounds U₃O₈ at the end of 2013 to 379 million pounds at the end of 2014. Our share of inferred mineral resources is 311 million pounds U₃O₈, an increase of 22 million pounds from the end of 2013

The variance in mineral resources was mainly the result of:

 

•

the addition of 1.9 million pounds of indicated resources and 16.8 million pounds of inferred resources at Rabbit Lake, primarily from delineation drilling

 

•

the removal of Dawn Lake mineral resources of 7.4 million pounds from our inventory due to uncertainty with the historical drilling data

 

•

the re-interpretation, estimate and categorization of Gas Hills/Peach resources

Qualified persons

The technical and scientific information discussed in this MD&A for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) was approved by the following individuals who are qualified persons for the purposes of NI 43-101:

 

 

80    CAMECO CORPORATION

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Important information about mineral reserve and resource estimates

Although we have carefully prepared and verified the mineral reserve and resource figures in this document, the figures are estimates, based in part on forward-looking information.

Estimates are based on our knowledge, mining experience, analysis of drilling results, the quality of available data and management’s best judgment. They are, however, imprecise by nature, may change over time, and include many variables and assumptions, including:

 

•

geological interpretation

 

•

extraction plans

 

•

commodity prices and currency exchange rates

 

•

recovery rates

 

•

operating and capital costs

There is no assurance that the indicated levels of uranium will be produced, and we may have to re-estimate our mineral reserves based on actual production experience. Changes in the price of uranium, production costs or recovery rates could make it unprofitable for us to operate or develop a particular site or sites for a period of time. See page 2 for information about forward-looking information.

Please see our mineral reserves and resources section of our annual information form for the specific assumptions, parameters and methods used for McArthur River, Inkai and Cigar Lake mineral reserve and resource estimates.

Important information for US investors

While the terms measured, indicated and inferred mineral resources are recognized and required by Canadian securities regulatory authorities, the US Securities and Exchange Commission (SEC) does not recognize them. Under US standards, mineralization may not be classified as a ‘reserve’ unless it has been determined at the time of reporting that the mineralization could be economically and legally produced or extracted. US investors should not assume that:

 

•

any or all of a measured or indicated mineral resource will ever be converted into proven or probable mineral reserves

 

•

any or all of an inferred mineral resource exists or is economically or legally mineable, or will ever be upgraded to a higher category. Under Canadian securities regulations, estimates of inferred resources may not form the basis of feasibility or pre-feasibility studies. Inferred resources have a great amount of uncertainty as to their existence and economic and legal feasibility.

The requirements of Canadian securities regulators for identification of ‘reserves’ are also not the same as those of the SEC, and mineral reserves reported by us in accordance with Canadian requirements may not qualify as reserves under SEC standards.

Other information concerning descriptions of mineralization, mineral reserves and resources may not be comparable to information made public by companies that comply with the SEC’s reporting and disclosure requirements for US domestic mining companies, including Industry Guide 7.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    81

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Mineral reserves

As at December 31, 2014 (100% basis – only the second last column shows our share)

PROVEN AND PROBABLE

(tonnes in thousands; pounds in millions)

 

				PROVEN												PROBABLE												TOTAL MINERAL RESERVES												OUR SHARE OF CONTENT (LBS U3O8)				METALLURGICAL RECOVERY (%)
PROPERTY		MINING METHOD		TONNES				GRADE % U3O8				CONTENT (LBS U3O8)				TONNES				GRADE % U3O8				CONTENT (LBS U3O8)				TONNES				GRADE % U3O8				CONTENT (LBS U3O8)
McArthur River		UG			497.8				18.71				205.3				555.2				11.43				139.9				1,053.0				14.87				345.2				241.0				98.7
Cigar Lake		UG			205.6				24.00				108.8				391.6				14.60				126.1				597.2				17.84				234.9				117.5				98.5
Rabbit Lake		UG			32.7				0.26				0.2				1,093.7				0.62				15.0				1,126.4				0.61				15.2				15.2				97.0
Key Lake		OP			67.5				0.50				0.7																67.5				0.50				0.7				0.6				98.7
Inkai		ISR			1,420.5				0.08				2.6				52,999.2				0.07				76.8				54,419.7				0.07				79.4				45.6				85.0
Smith Ranch-Highland		ISR			1,145.5				0.10				2.4				1,241.1				0.09				2.4				2,386.6				0.09				4.8				4.8				80.0
North Butte-Brown Ranch		ISR			753.4				0.08				1.4				875.2				0.08				1.5				1,628.6				0.08				2.9				2.9				60.0
Crow Butte		ISR			801.4				0.10				1.7																801.4				0.10				1.7				1.7				85.0
Total					4,924.4				—				323.1				57,155.9				—				361.6				62,080.3				—				684.6				429.2

Notes

UG – underground

OP – open pit

ISR – in situ recovery

Estimates in the above table:

 

•

use an average uranium price of $70 (US)/lb U3O8

 

•

are based on an average exchange rate of $1.00 US=$1.05-$1.10 Cdn

 

•

Totals may not add up due to rounding

We do not expect these mineral reserve estimates to be materially affected by metallurgical, environmental, permitting, legal, taxation, socio-economic, political, marketing or other relevant issues.

Metallurgical recovery

We report mineral reserves as the quantity of contained ore supporting our mining plans, and provide an estimate of the metallurgical recovery for each uranium property. The estimate of the amount of valuable product that can be physically recovered by the metallurgical extraction process is obtained by multiplying quantity of contained metal (content) by the planned metallurgical recovery percentage. The content and our share of uranium in the table above are before accounting for estimated metallurgical recovery.

 

82    CAMECO CORPORATION

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Mineral resources

As at December 31, 2014 (100% – only the shaded columns show our share)

MEASURED, INDICATED AND INFERRED

(tonnes in thousands; pounds in millions)

 

		MEASURED RESOURCES (M)												INDICATED RESOURCES (I)												TOTAL M+I CONTENT (LBS  U3O8)				OUR SHARE TOTAL M + I CONTENT (LBS U3O8)				INFERRED RESOURCES												OUR SHARE INFERRED CONTENT (LBS U3O8)
PROPERTY		TONNES				GRADE % U3O8				CONTENT (LBS U3O8)				TONNES				GRADE % U3O8				CONTENT (LBS U3O8)												TONNES				GRADE % U3O8				CONTENT (LBS U3O8)
McArthur River			100.8				3.55				7.9				12.0				10.03				2.7				10.6				7.4				350.9				7.38				57.1				39.9
Cigar Lake			4.7				12.00				1.2				19.6				8.09				3.4				4.7				2.3				293.7				16.22				105.0				52.5
Rabbit Lake															1,338.3				0.75				22.2				22.2				22.2				2,030.6				0.58				25.9				25.9
Millennium															1,442.6				2.39				75.9				75.9				53.0				412.4				3.19				29.0				20.2
Phoenix															166.4				19.13				70.2				70.2				21.1				8.6				5.80				1.1				0.3
Tamarack															183.8				4.42				17.9				17.9				10.3				45.6				1.02				1.0				0.6
Kintyre															4,315.4				0.58				55.2				55.2				38.7				950.2				0.46				9.6				6.7
Yeelirrie			24,013.5				0.17				92.4				12,626.5				0.13				34.9				127.3				127.3
Inkai															31,091.1				0.08				52.2				52.2				30.0				253,720.2				0.05				253.8				145.9
Smith Ranch-Highland			1,792.1				0.11				4.5				14,378.4				0.05				17.1				21.6				21.6				6,989.4				0.05				7.9				7.9
North Butte-Brown Ranch			232.6				0.08				0.4				5,530.3				0.07				8.4				8.8				8.8				294.5				0.07				0.4				0.4
Gas Hills-Peach			687.2				0.11				1.7				3,626.1				0.15				11.6				13.3				13.3				3,307.5				0.08				6.0				6.0
Crow Butte			1,133.1				0.24				6.0				1,354.9				0.29				8.6				14.6				14.6				1,135.2				0.12				2.9				2.9
Ruby Ranch															2,215.3				0.08				4.1				4.1				4.1				56.2				0.14				0.2				0.2
Shirley Basin			89.2				0.16				0.3				1,638.2				0.11				4.1				4.4				4.4				508.0				0.10				1.1				1.1
Total			28,053.2				—				114.4				79,938.9				—				388.4				502.8				379.0				270,103.0				—				501.0				310.6

Notes

Mineral resources do not include amounts that have been identified as mineral reserves.

Mineral resources do not have demonstrated economic viability. Totals may not add up due to rounding.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    83

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Additional information

Due to the nature of our business, we are required to make estimates that affect the amount of assets and liabilities, revenues and expenses, commitments and contingencies we report. We base our estimates on our experience, our best judgment, guidelines established by the Canadian Institute of Mining, Metallurgy and Petroleum and on assumptions we believe are reasonable.

We believe the following critical accounting estimates reflect the more significant judgments used in the preparation of our financial statements. These estimates affect all of our segments, unless otherwise noted.

Decommissioning and reclamation

In our uranium and fuel services segments, we are required to estimate the cost of decommissioning and reclamation for each operation, but we normally do not incur these costs until an asset is nearing the end of its useful life. Regulatory requirements and decommissioning methods could change during that time, making our actual costs different from our estimates. A significant change in these costs or in our mineral reserves could have a material impact on our net earnings and financial position. See Note 18 to the financial statements.

Property, plant and equipment

We depreciate property, plant and equipment primarily using the unit-of-production method, where the carrying value is reduced as resources are depleted. A change in our mineral reserves would change our depreciation expenses, and such a change could have a material impact on amounts charged to earnings.

We assess the carrying values of property, plant and equipment and goodwill every year, or more often if necessary. If we determine that we cannot recover the carrying value of an asset or goodwill, we write off the unrecoverable amount against current earnings. We base our assessment of recoverability on assumptions and judgments we make about future prices, production costs, our requirements for sustaining capital and our ability to economically recover mineral reserves. A material change in any of these assumptions could have a significant impact on the potential impairment of these assets.

In performing impairment assessments of long-lived assets, assets that cannot be assessed individually are grouped together into the smallest group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets. Management is required to exercise judgment in identifying these cash generating units.

Taxes

When we are preparing our financial statements, we estimate taxes in each jurisdiction we operate in, taking into consideration different tax rates, non-deductible expenses, valuation of deferred tax assets, changes in tax laws and our expectations for future results.

We base our estimates of deferred income taxes on temporary differences between the assets and liabilities we report in our financial statements, and the assets and liabilities determined by the tax laws in the various countries we operate in. We record deferred income taxes in our financial statements based on our estimated future cash flows, which includes estimates of non-deductible expenses. If these estimates are not accurate, there could be a material impact on our net earnings and financial position.

Commencement of production stage

When we determine that a mining property has reached the production stage, capitalization of development ceases, and depreciation of the mining property begins and is charged to earnings. Production is reached when management determines that the mine is able to produce at a consistent or sustainably increasing level. This determination is a matter of judgment. See note 2 to the financial statements for further information on the criteria that we used to make this assessment.

 

84    CAMECO CORPORATION

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Purchase price allocations

The purchase price related to a business combination or asset acquisition is allocated to the underlying acquired assets and liabilities based on their estimated fair values at the time of acquisition. The determination of fair value requires us to make assumptions, estimates and judgments regarding future events. The allocation process is inherently subjective and impacts the amounts assigned to individually identifiable assets and liabilities. As a result, the purchase price allocation impacts our reported assets and liabilities and future net earnings due to the impact on future depreciation and amortization expense and impairment tests.

Determination of joint control

We conduct certain operations through joint ownership interests. Judgment is required in assessing whether we have joint control over the investee, which involves determining the relevant activities of the arrangement and whether decisions around relevant activities require unanimous consent. Judgment is also required to determine whether a joint arrangement should be classified as a joint venture or joint operation. Classifying the arrangement requires us to assess our rights and obligations arising from the arrangement. Specifically, management considers the structure of the joint arrangement and whether it is structured through a separate vehicle. When structured through a separate vehicle, we also consider the rights and obligations arising from the legal form of the separate vehicle, the terms of the contractual arrangements and other facts and circumstances, when relevant. This judgment influences whether we equity account or proportionately consolidate our interest in the arrangement.

Controls and procedures

We have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2014, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.

Management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), supervised and participated in the evaluation, and concluded that our disclosure controls and procedures are effective to provide a reasonable level of assurance that the information we are required to disclose in reports we file or submit under securities laws is recorded, processed, summarized and reported accurately, and within the time periods specified. It should be noted that, while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect the disclosure controls and procedures or internal control over financial reporting to be capable of preventing all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Management, including our CEO and our CFO, is responsible for establishing and maintaining internal control over financial reporting and conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2014. In 2014, we updated our control framework to COSO 2013 as required; however, we have not made any change to our internal control over financial reporting during the 2014 fiscal year that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

New standards and interpretations not yet adopted

A number of new standards and amendments to existing standards are not yet effective for the year ended December 31, 2014, and have not been applied in preparing the consolidated financial statements. The following standards and amendments to existing standards have been published and are mandatory for our accounting periods beginning on or after January 1, 2016, unless otherwise noted. We do not intend to early adopt any of the following amendments to existing standards and we do not expect the amendments to have a material impact on our financial statements.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    85

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IAS16, Property, Plant and Equipment (IAS 16) and IAS 38, Intangible Assets (IAS 38) – In May 2014, the IASB issued amendments to IAS16 and IAS 38. The amendments are to be applied prospectively. The amendments clarify the factors to be considered in assessing the technical or commercial obsolescence and the resulting depreciation period of an asset and state that a depreciation method based on revenue, is not appropriate.

IFRS 11, Joint Arrangements (IFRS 11) – In May 2014, the IASB issued amendments to IFRS 11. The amendments in IFRS 11 are to be applied prospectively. The amendments clarify the accounting for the acquisition of interests in joint operations and require the acquirer to apply the principles of business combinations accounting in IFRS 3 Business Combinations.

IFRS 10, Consolidated Financial Statements (IFRS 10) and IAS 28, Investments in Associate and Joint Ventures (IAS 28) – In September 2014, the IASB issued amendments to IFRS 10 and IAS 28. The amendments provide clarification on the recognition of gains or losses upon the sale or contribution of assets between an investor and its associate or joint venture.

IFRS 5, Non-Current Assets Held for Sale and Discontinued Operations (IFRS 5) – In September 2014, the IASB issued amendments to IFRS 5. The amendments are to be applied prospectively, with earlier application permitted. Assets are generally disposed of either through sale or through distribution to owners. The amendments clarify the application of IFRS 5 when changing from one of these disposal methods to the other.

IFRS 7, Financial Instruments: Disclosures (IFRS 7) – In September 2014, the IASB issued amendments to IFRS 7. The amendments in IFRS 7 are to be applied retrospectively, with earlier application permitted. The amendments clarify the disclosure required for any continuing involvement in a transferred asset that has been derecognized. The amendments also provide guidance on disclosures regarding the offsetting of financial assets and financial liabilities in interim financial reports.

IAS 34 Interim Financial Reporting (IAS 34) – In September 2014, the IASB issued amendments to IAS 34. The amendments are to be applied retrospectively, with earlier application permitted. The amendments provide additional guidance on interim disclosures and whether they are provided in the interim financial statements or incorporated by cross-reference between the interim financial statements and other financial disclosures.

IFRS 15, Revenue from Contracts with Customers (IFRS 15) – In May 2014, the IASB issued IFRS 15. IFRS 15 is effective for periods beginning on or after January 1, 2017 and is to be applied retrospectively. IFRS 15 clarifies the principles for recognizing revenue from contracts with customers. The extent of the impact of adoption of IFRS 15 has not yet been determined.

IFRS 9, Financial Instruments (IFRS 9) – In July, 2014, the International Accounting Standards Board (IASB) issued IFRS 9. IFRS 9 replaces the current multiple classification and measurement models for financial assets and liabilities with a single model that has only two classification categories: amortized cost and fair value. The basis of classification depends on the entity’s business model and the contractual cash flow characteristics of the financial asset or liability. It also introduces additional changes relating to financial liabilities and aligns hedge accounting more closely with risk management.

IFRS 9 is effective for annual periods beginning on or after January 1, 2018, with early adoption of the new standard permitted. We do not intend to early adopt IFRS 9. The extent of the impact of adoption of IFRS 9 has not yet been determined.

 

86    CAMECO CORPORATION

EXHIBIT 99.4

For fiscal years ended December 31, 2014 and December 31, 2013, KPMG LLP and its affiliates were paid by Cameco Corporation and its subsidiaries the following fees:

 

(Cdn$)		2014				% of Total Fees				2013				% of Total Fees
Audit Fees:
Cameco		$	1,743,300				48.7	%		$	1,443,700				45.9	%
Subsidiaries			798,900				22.4	%			879,500				28.0	%
Total Audit Fees		$	2,542,200				71.1	%		$	2,323,200				73.9	%
Audit-Related Fees:
Translation services		$	178,500				5.0	%		$	67,200				2.1	%
Pensions and other			177,800				5.0	%			104,300				3.3	%
Total Audit-Related Fees		$	356,300				10.0	%		$	171,500				5.4	%
Tax Fees:
Compliance		$	307,800				8.6	%		$	252,500				8.0	%
Planning and advice			367,400				10.3	%			398,600				12.7	%
Total Tax Fees		$	675,200				18.9	%		$	651,100				20.7	%
All Other Fees:			—				0.0	%			—				0.0	%
Total Fees:		$	3,573,700				100.0	%		$	3,145,800				100.0	%

Pre-Approval Policies and Procedures

As part of Cameco Corporation’s corporate governance practices, under its committee charter, the audit and finance committee is required to pre-approve the audit and non-audit services performed by the external auditors. The audit and finance committee pre-approves the audit and non-audit services up to a maximum specified level of fees. If fees relating to audit and non-audit services are expected to exceed this level or if a type of audit or non-audit service is to be performed that previously has not been pre-approved, then separate pre-approval by Cameco Corporation’s audit and finance committee or audit and finance committee chair, or in the absence of the audit and finance committee chair, the chair of the board, is required. All pre-approvals granted pursuant to the delegated authority must be presented by the member(s) who granted the pre-approvals to the full audit and finance committee at its next meeting. The audit and finance committee has adopted a written policy to provide procedures to implement the foregoing principles. For each of the years ended December 31, 2014 and 2013, 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.

EXHIBIT 99.5

Contractual Cash Obligations

 

As at December 31, 2014 (Cdn$ millions)		Total				Due in Less Than 1 Year				Due in 1 – 3 Years				Due in 4 – 5 Years				Due After 5 Yrs
Long-term debt			1,500				—				—				500				1,000
Interest on long-term debt			614				69				139				139				267
Provision for reclamation			874				19				60				75				720
Provision for waste disposal			18				2				9				5				2
Other liabilities			62				—				—				—				62
Capital commitments			99				99				—				—				—
Unconditional product purchase commitments 1			2,168				733				648				285				502
Total contractual cash obligations			5,335				922				856				1,004				2,553

 

1	Denominated in US dollars. Converted to Canadian dollars at the December 31, 2014 rate of Cdn $1.16.

Commercial Commitments

 

As at December 31, 2014 (Cdn$ millions)		Total amounts committed
Standby letters of credit 1			942
Total commercial commitments			942

 

1

The standby letters of credit maturing in 2015 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.

EXHIBIT 99.6

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Cameco Corporation

We have audited Cameco Corporation’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) 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, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

---

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated statements of financial position of Cameco Corporation as of December 31, 2014 and December 31, 2013, and the related consolidated statements of earnings, comprehensive income, changes in equity, and cash flows for the years then ended, and our report dated February 5, 2015 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Chartered Accountants

Saskatoon, Canada

February 5, 2015

EXHIBIT 99.7

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Board of Directors of Cameco Corporation

We have audited the accompanying consolidated statements of financial position of Cameco Corporation as of December 31, 2014 and December 31, 2013 and the related consolidated statements of earnings, comprehensive income, changes in equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of Cameco Corporation’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cameco Corporation as of December 31, 2014 and December 31, 2013, and its consolidated financial performance and its consolidated cash flows for the years then ended in conformity 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, 2014, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 5, 2015 expressed an unqualified opinion on the effectiveness of Cameco Corporation’s internal control over financial reporting.

/s/ KPMG LLP

Chartered Accountants

Saskatoon, Canada

February 5, 2015

EXHIBIT 99.8

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Cameco Corporation

We consent to the use of our reports, included in this annual report on Form 40-F, each dated February 5, 2015, with respect to:

 

•

our Auditors’ Report on the consolidated statements of financial position of Cameco Corporation (the “Corporation”) as at December 31, 2014 and December 31, 2013, the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the years then ended;

 

•

our Report of Independent Registered Public Accounting Firm in accordance with the standards of the Public Company Accounting Oversight Board (United States) on the consolidated statements of financial position of the Corporation as at December 31, 2014 and December 31, 2013, the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the years then ended; and

 

•

our Report of Independent Registered Public Accounting Firm on the Corporation’s internal control over financial reporting as of December 31, 2014.

We also consent to the incorporation by reference of such reports in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-196422) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statements (Nos. 333-181577 and 333-200678) on Form F-10.

/s/ KPMG LLP

Chartered Accountants

Saskatoon, Canada

March 6, 2015

EXHIBIT 99.9

I, Tim Gitzel, certify that:

 

1.	I have reviewed this annual report on Form 40-F of Cameco Corporation;

 

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

 

4.

The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

 

a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c)

evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d)

disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

 

5.	The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

 

a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

---

b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: March 6, 2015

 

EXHIBIT 99.10

I, Grant Isaac, certify that:

 

1.	I have reviewed this annual report on Form 40-F of Cameco Corporation;

 

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

 

4.

The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

 

a)

designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b)

designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

 

c)

evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d)

disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and

 

5.	The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):

 

a)

all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and

---

b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

Date: March 6, 2015

 

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, 2014, as filed with the U.S. Securities and Exchange Commission on the date hereof (the “Report”), I, Tim Gitzel, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

 

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

By:		/s/ Tim Gitzel
Name:		Tim Gitzel
Title:		President and Chief Executive Officer

March 6, 2015

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, 2014, as filed with the U.S. Securities and Exchange Commission on the date hereof (the “Report”), I, Grant Isaac, Senior Vice-President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

 

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

 

2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

By:		/s/ Grant Isaac
Name:		Grant Isaac
Title:		Senior Vice-President and Chief Financial Officer

March 6, 2015

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 Projects – Uranium Operating Properties – McArthur River/Key Lake”, “Operations and Projects – Uranium Operating Properties – Cigar Lake”, “Operations and 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, 2014 dated March 6, 2015 for the McArthur River/Key Lake, Cigar Lake and Inkai properties; and

 

(b)

under the headings “Our Operations and Projects - Uranium Operating Properties – McArthur River/Key Lake”, “Our Operations and Projects – Uranium Operating Properties – Cigar Lake”, “Our Operations and Projects – Uranium Operating Properties – Inkai”, and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2014 dated February 9, 2015 for the McArthur River/Key Lake, Cigar Lake and Inkai properties,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-196422) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statements (Nos.333-181577 and 333-200678) on Form F-10.

Sincerely,

 

/s/ Alain G. Mainville
Name:		Alain G. Mainville, P. Geo.
Title:		Director,   Mineral Resources Management,   Cameco Corporation

Date: March 6, 2015

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 Projects – Uranium Operating Properties – Cigar Lake”, “Mineral Reserves and Resources” and “Governance – Interest of Experts” in the Corporation’s Annual Information Form for the year ended December 31, 2014 dated March 6, 2015 for the Cigar Lake property; and

 

(b)

under the headings “Our Operations and Projects – Uranium Operating Properties – Cigar Lake” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2014 dated February 9, 2015 for the Cigar Lake property,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-196422) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statements (Nos.333-181577 and 333-200678) on Form F-10.

Sincerely,

 

/s/ Eric Paulsen
Name:		Eric Paulsen, P. Eng., Pr. Eng.
Title:		Chief Metallurgist,   Technical Services,   Cameco Corporation

Date: March 6, 2015

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 Projects – Uranium Operating Properties – Cigar Lake”, “Mineral Reserves and Resources” and “Governance – Interest of Experts” in the Corporation’s Annual Information Form for the year ended December 31, 2014 dated March 6, 2015 for the Cigar Lake property; and

 

(b)

under the headings “ Our Operations and Projects – Uranium Operating Properties – Cigar Lake” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2014 dated February 9, 2015 for the Cigar Lake property,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-196422) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statements (Nos.333-181577 and 333-200678) on Form F-10.

Sincerely,

 

/s/ C. Scott Bishop
Name:		C. Scott Bishop, P. Eng.
Title:		Manager, Technical Services,   Cameco Corporation

Date: March 6, 2015

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 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, 2014 dated March 6, 2015 for the Inkai property; and

 

(b)

under the headings “Our Operations and Projects – Uranium Operating Properties – Inkai” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2014 dated February 9, 2015 for the Inkai property,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-196422) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statements (Nos. 333-181577 and 333-200678) on Form F-10.

Sincerely,

 

/s/ Darryl Clark
Name: Darryl Clark, P. Geo.
Title:   General Director, JV Inkai LLP

Date: March 6, 2015

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 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, 2014 dated March 6, 2015 for the Inkai property; and

 

(b)

under the headings “Our Operations and Projects – Uranium Operating Properties – Inkai” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2014 dated February 9, 2015 for the Inkai property,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-196422) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statements (Nos.333-181577 and 333-200678) on Form F-10.

Sincerely,

 

/s/ Lawrence Reimann
Name:		Lawrence Reimann, P. Eng.
Title:		Manager, Technical Services,   Power Resources, Inc.   (operating as Cameco Resources)

Date: March 6, 2015

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 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, 2014 dated March 6, 2015 for the Inkai property; and

 

(b)

under the headings “Our Operations and Projects – Uranium Operating Properties – Inkai” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2014 dated February 9, 2015 for the Inkai property,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-196422) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statements (Nos. 333-181577 and 333-200678) on Form F-10.

Sincerely,

 

/s/ Bryan Soliz
Name:		Bryan Soliz, P. Geo.
Title:		Principal Geologist, Mineral Resources Management, Cameco Corporation

Date: March 6, 2015

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 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, 2014 dated March 6, 2015 for the McArthur River/Key Lake properties; and

 

(b)

under the headings “Our Operations and Projects – Uranium Operating Properties – McArthur River/Key Lake” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2014 dated February 9, 2015 for the McArthur River/Key Lake properties,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-196422) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statements (Nos.333-181577 and 333-200678) on Form F-10.

Sincerely,

 

/s/ Baoyao Tang
Name:		Baoyao Tang, P. Eng.
Title:		Technical Superintendent,   McArthur River,   Cameco Corporation

Date: March 6, 2015

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 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, 2014 dated March 6, 2015 for the McArthur River/Key Lake properties; and

 

(b)

under the headings “Our Operations and Projects – Uranium Operating Properties – McArthur River/Key Lake” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2014 dated February 9, 2015 for the McArthur River/Key Lake properties,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-196422) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statements (Nos.333-181577 and 333-200678) on Form F-10.

Sincerely,

 

/s/ David Bronkhorst
Name:		David Bronkhorst, P. Eng.
Title:		Vice-President, Mining and Technology, Cameco Corporation

Date: March 6, 2015

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 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, 2014 dated March 6, 2015 for the McArthur River/Key Lake properties; and

 

(b)

under the headings “Our Operations and Projects – Uranium Operating Properties – McArthur River/Key Lake” and “Mineral Reserves and Resources” in Management’s Discussion and Analysis of Financial Condition and Results of Operation for the year ended December 31, 2014 dated February 9, 2015 for the McArthur River/Key Lake properties,

(collectively the “Technical Information”) in the Form 40-F, and to the inclusion and incorporation by reference of information derived from the Technical Information in the Form 40-F.

I also hereby consent to the incorporation by reference of such Technical Information in the registration statements (Nos. 333-11736, 333-6180 and 333-139165) on Form S-8 for the Cameco Corporation Stock Option Plan, registration statement (No. 333-196422) on Form S-8 for the Cameco Corporation Employee Share Ownership Plan and registration statements (Nos. 333-181577 and 333-200678) on Form F-10.

Sincerely,

 

/s/ Leslie (Les) D. Yesnik
Name:		Leslie (Les) D. Yesnik, P. Eng.
Title:		General Manager,   Cigar Lake,   Cameco Corporation

Date: March 6, 2015