EX-99.3 4 d685238dex993.htm EX-99.3 EX-99.3

EXHIBIT 99.3

Cameco Corporation

2013 Management’s Discussion and Analysis

February 10, 2014

 

 

LOGO

Management’s discussion and analysis

February 10, 2014

 

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

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

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

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

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

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

Caution about forward-looking information

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

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

 

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

 

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

 

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

 

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

 

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

Examples of forward-looking information in this MD&A

 

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

 

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

 

  •   our 2014 objectives

 

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

 

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

 

  •   future tax payments and rates

 

  •   our consolidated outlook for the year and the outlook for our uranium, fuel services and NUKEM segments for 2014
  •   our expectation that existing cash balances and operating cash flows will meet our anticipated 2014 capital requirements without the need for any significant additional funding

 

  •   our expectations for 2014, 2015 and 2016 capital expenditures

 

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

 

  •   our uranium price sensitivity analysis

 

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

 

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

 

  •   our mineral reserve and resource estimates
 

 

Material risks

 

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

 

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

 

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

 

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

 

  •   we are unable to enforce our legal rights under our existing agreements, permits or licences
  •   we are subject to litigation or arbitration that has an adverse outcome, including lack of success in our dispute with CRA

 

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

 

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

 

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

 

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

 

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

 

2     CAMECO CORPORATION

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

 

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

 

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

 

  •   our uranium and conversion suppliers fail to fulfill delivery commitments

 

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

 

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

 

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

 

Material assumptions

 

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

 

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

 

  •   our expected production level and production costs

 

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

 

  •   our expectations regarding spot prices and realized prices for uranium, and other factors discussed on page 42, Price sensitivity analysis: uranium

 

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

 

  •   our expectations about the outcome of the dispute with CRA

 

  •   our decommissioning and reclamation expenses

 

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

 

  •   the geological, hydrological and other conditions at our mines

 

  •   our Cigar Lake mining and production plans succeed, including the additional jet boring system is acquired on schedule, the jet boring mining method works as anticipated, and the deposit freezes as planned
  •   mill modifications and commissioning of the McClean Lake mill are completed as planned and the mill is able to process Cigar Lake ore as expected

 

  •   our McArthur River development, mining and production plans succeed

 

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

 

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

 

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    3

The nuclear fuel cycle

 

LOGO

 

1 Mining

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

 

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

 

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

 

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

 

1 Milling

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

 

2 Refining

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

 

3 Conversion

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

4 Enrichment

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

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

 

5 Fuel manufacturing

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

 

6 Generation

Nuclear reactors are used to generate electricity.

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

Spent fuel management

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

 

 

4     CAMECO CORPORATION

About Cameco

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

Strengths

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

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

Business segments

 

URANIUM

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

Product

 

•   uranium concentrates (U3O8)

Mineral reserves and resources

Mineral reserves

 

•   approximately 443 million pounds proven and probable

Mineral resources

 

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

Global exploration

 

•   focused on four continents

 

•   approximately 2.0 million hectares of land

Operating properties

 

•   McArthur River and Key Lake, Saskatchewan

 

•   Rabbit Lake, Saskatchewan

 

•   Smith Ranch-Highland, Wyoming

 

•   Crow Butte, Nebraska

 

•   Inkai, Kazakhstan

Development project

 

•   Cigar Lake, Saskatchewan

Projects under evaluation

 

•   Inkai blocks 1 and 2 production increase, Kazakhstan

 

•   Inkai block 3, Kazakhstan

 

•   Millennium, Saskatchewan

 

•   Yeelirrie, Australia

 

•   Kintyre, Australia
 

 

FUEL SERVICES

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

Products

 

•   uranium trioxide (UO3)

 

•   uranium hexafluoride (UF6)

(control about 25% of world conversion capacity)

 

•   uranium dioxide (UO2)

 

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

Operations

 

•   Blind River refinery, Ontario

(refines uranium concentrates to UO3)

 

•   Port Hope conversion facility, Ontario

(converts UO3 to UF6 or UO2)

 

•   Cameco Fuel Manufacturing Inc., Ontario

(manufactures fuel bundles and reactor components)

 

•   a toll conversion agreement with Springfields Fuels Ltd.

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

 

 

NUKEM

 

Our ownership of NUKEM GmbH (NUKEM) provides us with access to one of the world’s leading traders of uranium and uranium-related products. We acquired NUKEM in January, 2013.

Activity

 

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

 

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    5

Other fuel cycle investments

ENRICHMENT

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

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

Investment

 

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

 

GLOBAL PRESENCE

 

LOGO

 

6     CAMECO CORPORATION

KEY MARKET FACTS

 

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

 

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

 

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

 

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

 

•   In emerging nuclear countries, construction has begun in the United Arab Emirates (UAE) and Belarus, and planning for first reactors is underway in Turkey, Vietnam, Bangladesh, Poland, Jordan and Saudi Arabia.
•   Over the next decade, we expect demand for uranium to grow by an average of 4% per year. To meet global demand, we expect about two-thirds of uranium supply will come from mines that are currently in operation, about 15% from finite sources of secondary supply (mainly government inventories and limited recycling), and about 20% will have to come from new sources of supply.

 

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    7

2013 highlights

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

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

Strong financial performance

Our financial results remained strong in 2013:

 

•   record annual revenue of $2.4 billion

 

•   annual gross profit of $607 million

 

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

 

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

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

 

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

 

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

 

•   lower exploration expenditures

 

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

partially offset by:

 

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

 

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

 

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

 

HIGHLIGHTS

DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED)

    2013      2012      CHANGE  

Revenue

      2,439         1,891         29 % 

Gross profit

      607         540         12 % 

Net earnings attributable to equity holders

      318         253         26 % 

$ per common share (diluted)

      0.81         0.64         27 % 

Adjusted net earnings (non-IFRS, see page 28)

      445         434         3 % 

$ per common share (adjusted and diluted)

      1.12         1.10         2 % 

Cash provided by operations (after working capital changes)

      530         579         (8 )% 

 

8     CAMECO CORPORATION

Solid progress in our uranium segment this year

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

We also continued to advance our exploration activities, spending $9 million on seven brownfield exploration projects, $7 million on our projects under evaluation in Australia, and $13 million for resource definition at Inkai and at our US operations. We spent about $44 million on regional exploration programs, mostly in Saskatchewan, followed by Australia and the United States.

Updates on our other segments and investments

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

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

On January 31, 2014, we announced the sale of our 31.6% limited partnership interest in BPLP and related entities to BPC Generation Infrastructure Trust, one of the limited partners in BPLP, for $450 million. The effective date for the sale is December 31, 2013. Under the agreements governing BPLP, the limited partners have rights of first offer upon a sale by us. Closing of the transaction is subject to completion or waiver of the right of first offer process by the other limited partners and receipt of certain regulatory approvals.

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    9

HIGHLIGHTS

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

 

SHARES AND STOCK OPTIONS OUTSTANDING

At February 6, 2014, we had:

 

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

 

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

DIVIDEND POLICY

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

 

 

10     CAMECO CORPORATION

The nuclear energy industry today

The long-term outlook for the uranium industry continues to be very positive, despite the uncertainty that exists today. Against the backdrop of the world’s growing need for safe, clean, reliable and large-scale sources of energy, nuclear energy continues to play a significant role in the global energy mix. The challenge for the industry is the pathway and timing of the transition from today’s stagnant, over-supplied short-term market to the promise of nuclear growth and positive uranium market conditions in the long term.

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

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

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

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    11

Industry prices

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

 

     2013      2012      CHANGE  

Uranium ($US/lb U3O8) 1

         

Average spot market price

      38.17         48.40         (21 )% 

Average long-term price

      54.13         60.13         (10 )% 

Fuel services ($US/kgU as UF6)1

         

Average spot market price

         

North America

      9.60         7.99         20 % 

Europe

      10.07         8.56         18 % 

Average long-term price

         

North America

      16.50         16.75         (1 )% 

Europe

      17.17         17.25         —     

Note: the industry does not publish UO2 prices.

         

Electricity ($/MWh)

         

Average Ontario electricity spot price

      25         23         9 % 

 

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

 

LOGO

 

12     CAMECO CORPORATION

World consumption and production

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

We expect global uranium consumption to increase to about 170 million pounds in 2014, and global production to be approximately 160 million pounds. Secondary supplies should continue to bridge the gap.

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

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

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

 

LOGO

Contract volumes

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

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

 

LOGO

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    13

The long-term view

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

 

LOGO

New reactor outlook

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

 

LOGO

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

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

 

14     CAMECO CORPORATION

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

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

DEMAND FOR URANIUM IS GROWING

Not surprisingly, as the number of reactors grows, so too does the demand for uranium. Over the next decade, we expect world demand to grow at an average annual growth rate of about 4%, totaling approximately 2.2 billion pounds from 2014 – 2023. As a result of that growth, by 2023, we expect annual world consumption to be approximately 240 million pounds, plus about 20 million pounds per year for strategic inventory building, totaling 260 million pounds of world demand.

SUPPLY UNCERTAINTY

While demand is expected to increase over the next decade, many producers have announced delays and cancellations to their projects, which could have an effect on the longer term outlook for the uranium industry. Complicating the supply outlook further is the possibility of some projects, primarily driven by sovereign interests, moving forward in the near term despite market conditions.

 

LOGO

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    15

Our strategy

Our strategy remains focused on taking advantage of the long-term growth we see coming in our industry, while maintaining the ability to respond to market conditions as they evolve. As a result of the longer-than-anticipated market uncertainty, we are adjusting our plans in line with this focus.

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

 

•   the pace of Japanese reactor restarts

 

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

 

•   when long-term contracting resumes in meaningful quantities

 

•   the development and execution of new uranium supply projects

 

•   continued performance of existing supply

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

We plan to:

 

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

 

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

 

•   ensure continued reliable, low-cost production at Inkai

 

•   successfully bring on and ramp up production at Cigar Lake

 

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

 

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

Capital allocation

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

 

•   create the greatest long-term value for our shareholders

 

•   allow us to maintain our investment grade rating

 

•   ensure we execute on our dividend policy

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

Reinvestment

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

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

 

16     CAMECO CORPORATION

Return

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

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

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

Marketing Strategy

As with our corporate strategy and our approach to capital allocation, the purpose of our marketing strategy is to deliver value and secure a solid base of earnings and cash flow, by maintaining a balanced contract portfolio that optimizes our realized price.

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

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

In addition, we are active in the spot market, buying and selling uranium where it is beneficial for us. With our purchase of NUKEM, we have enhanced our ability to participate in this regard as they are one of the world’s leading traders of uranium and uranium-related products. We undertake activity in the spot market prudently, looking at the spot price and other business factors to decide whether it is appropriate to purchase or sell into the spot market. This activity gives us insight into the underlying market fundamentals and is a source of profit.

OPTIMIZING REALIZED PRICE

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

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

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

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

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    17

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

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

CONTRACT PORTFOLIO STATUS

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

Customers – U3O8:

 

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

 

•   41% of volume to Asia

 

•   23% of volume to Europe

 

•   five largest customers account for 50% of commitments

Customers – UF6 conversion:

 

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

 

•   25% of volume to Asia

 

•   35% of volume to Europe

 

•   five largest customers account for 54% of commitments

Managing our contract commitments and costs

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

 

•   from our existing production

 

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

 

•   from our existing inventory

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

 

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

 

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

 

•   purchases under existing and/or new arrangements

 

•   discretionary use of inventories

 

•   market opportunities

PRODUCTION

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

 

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

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

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

PURCHASES AND INVENTORY

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

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

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

OUTLOOK

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    19

Responsibility

 

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

 

•   preventing injury, ill health and pollution

 

•   complying with and moving beyond legal and other requirements

 

•   keeping risks at levels as low as reasonably achievable

 

•   ensuring quality of processes, products and services

Focus on long-term sustainability

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

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

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

 

 

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

Safety

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

 

•   safety is our first priority

 

•   we are all accountable for safety

 

•   safety is part of everything we do

 

•   safety leadership is critical to us

 

•   we are a learning organization

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

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

A clean environment

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

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

Reducing our impact

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

 

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

 

 

20     CAMECO CORPORATION

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

 

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

People

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

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

Supportive communities

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

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

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

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

For example, in northern Saskatchewan in 2013:

 

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

 

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

 

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    21

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

 

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

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

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

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

 

22     CAMECO CORPORATION

Measuring our results

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

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

 

•   outstanding financial performance

 

•   a safe, healthy and rewarding workplace

 

•   a clean environment

 

•   supportive communities

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

 

OUTSTANDING FINANCIAL PERFORMANCE

2013 OBJECTIVES

   

RESULTS

Earnings Measures

 

• Achieve targeted adjusted net earnings and cash flow from operations (before working capital changes).

   

Exceeded

 

• Adjusted net earnings1 were $445 million, 11% higher than our target.

 

• Cash flow from operations (before working capital changes)1 was $669 million, 11% higher than our target.

Capital Management

 

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

   

Partially achieved

 

• Our cost performance indicator for 2013 was 0.87 (over-budget), above the threshold however below the target of 1.0, due to cost overruns and necessary scope additions at Cigar Lake.

 

• Our schedule performance indicator was below our threshold for 2013, resulting in a zero rating.

Cigar Lake

 

•     Achieve production at Cigar Lake in 2013.

   

Not achieved

 

•     In 2013, we made strong progress toward production, including jetting in waste, assembling a second jet boring system underground, and commissioning most of the other mine systems. We were also successful in obtaining the required construction and operating licence. However, production of the first packaged pounds was delayed as a result of additional work to ensure the safe, efficient operation of the mine and mill. In December, we began jet boring in ore, and have since completed the first cavity in ore.

 

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    23

SAFE, HEALTHY AND REWARDING WORKPLACE

2013 OBJECTIVES

   

RESULTS

•     Strive for no lost-time injuries (LTI) at all Cameco-operated sites and, at a minimum, maintain a long-term downward trend in combined employee and contractor injury frequency and severity, and radiation doses.

   

Exceeded

 

•     Overall safety performance was strong in 20131. Injury rates trended downward across the company and were better than expected. Average radiation doses remained low and stable. In the past two years, we have met our targets for safety performance.

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

   

Achieved

 

•     We were listed as both a Top 100 Employer (for the fifth year in a row) and one of the Financial Post’s 10 Best Companies to Work For, in addition to receiving awards for being among Saskatchewan’s Top 10 Employers, Canada’s Best Diversity Employers, Top Employer for Canadians Over 40, and a Top Employer for Young People.

 

•     Our 2013 turnover rate of 8.3% (excluding the impact of restructuring) was lower than our target of 9%.

 

•     The expected turnover rate for new hires within the first year of employment was slightly higher than expected at 12.7%.

 

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

 

CLEAN ENVIRONMENT   

2013 OBJECTIVES

   

RESULTS

•     Do not incur an incident that results in moderate or significant environmental impacts or remediation costs of greater than or equal to $1M or which has reasonable potential to result in significant negative impact on the company’s reputation. Achieve a decreasing trend for environmental incidents, measured as less than the long-term average.

   

Exceeded

 

• There were no significant environmental incidents in 2013, and our reportable environmental incidents were significantly lower than our long-term average of 38, with only 22 over the course of the year.

 

SUPPORTIVE COMMUNITIES     

2013 OBJECTIVES

   

RESULTS

•     Increase employment of residents of Saskatchewan’s north (RSN) by 2% (15 net additions) over 2012.

 

•     Support northern business development opportunities by procuring at least 75% of northern services from northern Saskatchewan vendors.

   

Not achieved

 

•     Overall RSN employment decreased seven positions from 2012 to 747 positions. However, we were successful in adding 18 RSN employees at Cigar Lake, and maintained a 50% RSN workforce overall at the northern sites.

 

•     Only 67% of northern services were procured from northern Saskatchewan vendors. We did not achieve our target due to disproportionate growth in overall spend, cost efficiencies and a temporary increase in expenditures, largely growth capital at Cigar Lake which required specialized services that were not available from northern Saskatchewan vendors. Over the past few years, overall spend has grown faster than the growth in capacity of northern vendors. Despite not achieving our targeted ratio, the nominal business volume with northern Saskatchewan vendors has more than doubled since 2009.

 

24     CAMECO CORPORATION

2014 objectives

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

OUTSTANDING FINANCIAL PERFORMANCE

 

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

 

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

 

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

SAFE, HEALTHY AND REWARDING WORKPLACE

 

•   Improve workplace safety performance at all sites.

 

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

CLEAN ENVIRONMENT

 

•   Improve environmental performance at all sites.

SUPPORTIVE COMMUNITIES

 

•   Build and sustain strong stakeholder support for our activities.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    25

Financial results

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

 

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

 

26     CAMECO CORPORATION

2013 consolidated financial results

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

 

HIGHLIGHTS

DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED)

    2013      2012      20111      CHANGE FROM
2012 TO 2013		  

Revenue

      2,439         1,891         2,384         29 % 

Gross profit

      607         540         776         12 % 

Net earnings attributable to equity holders

      318         253         450         26 % 

$ per common share (basic)

      0.81         0.64         1.14         27 % 

$ per common share (diluted)

      0.81         0.64         1.14         27 % 

Adjusted net earnings (non-IFRS, see page 28)

      445         434         509         3 % 

$ per common share (adjusted and diluted)

      1.12         1.10         1.29         2 % 

Cash provided by operations (after working capital changes)

      530         579         745         (8 )% 

 

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

Net earnings

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

 

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

 

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

 

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

 

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

partially offset by:

 

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

 

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

 

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

THREE-YEAR TREND

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

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

Impairment charge on non-producing assets

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    27

Non-IFRS measures

ADJUSTED NET EARNINGS

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

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

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

 

($ MILLIONS)

    2013     2012     2011  

Net earnings attributable to equity holders

      318        253        450   

Adjustments

       

Adjustments on derivatives1 (pre-tax)

      56        17        80   

Impairment charge on non-producing property

      70        168        —     

NUKEM inventory write-down

      14        —          —     

Loss on exploration properties

      15        —          —     

Income taxes on adjustments

      (28 )      (4 )      (21 ) 

Adjusted net earnings

      445        434        509   

 

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

 

28     CAMECO CORPORATION

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

 

($ MILLIONS)

       

Adjusted net earnings – 2012

      434   
     

 

 

  

Change in gross profit by segment

(we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation and amortization (D&A), net of hedging benefits)

   
Uranium    Lower sales volume      (2 ) 
   Higher realized prices ($US)      21   
   Foreign exchange impact on realized prices      48   
   Higher costs      (30 ) 
   Hedging benefits      (66 ) 
     

 

 

  
   change – uranium      (29 ) 
     

 

 

  
Fuel services    Higher sales volume      3   
   Higher realized prices ($Cdn)      7   
   Lower costs      1   
   Hedging benefits      (8 ) 
     

 

 

  
   change – fuel services      3   
     

 

 

  
NUKEM    Gross profit, net of pretax inventory adjustment      33   
     

 

 

  
   change – NUKEM      33   
     

 

 

  

Other changes

   

Lower earnings from equity investment in BPLP

      (48 ) 

Contract termination charge

      30   

Higher administration expenditures

      (4 ) 

Lower exploration expenditures

      24   

Loss on equity accounted investments

      (5 ) 

Lower income taxes

      15   

Other

      (8 ) 
     

 

 

  

Adjusted net earnings – 2013

      445   
     

 

 

  

THREE-YEAR TREND

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

The 15% decrease from 2011 to 2012 resulted from:

 

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

 

•   higher charges for administration and exploration

partially offset by:

 

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

 

•   lower income taxes

The 3% increase from 2012 to 2013 resulted from:

 

•   addition of gross profit from NUKEM

 

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

 

•   lower income taxes

partially offset by:

 

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    29

Revenue

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

 

($ MILLIONS)

       

Revenue – 2012

      1,891   

Uranium

   

Lower sales volume

      (7 ) 

Higher realized prices ($Cdn)

      68   

Fuel services

   

Higher sales volume

      21   

Higher realized prices ($Cdn)

      7   

NUKEM

      465   

Other

      (6 ) 
  

 

 

  

Revenue – 2013

      2,439   
  

 

 

  

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

THREE-YEAR TREND

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

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

Average realized prices

 

       2013      2012      2011      CHANGE FROM
2012 TO 2013		  

Uranium1

    $ US/lb         48.35         47.72         49.17         1 % 
   $ Cdn/lb         49.81         47.72         49.18         4 % 

Fuel services

    $ Cdn/kgU         18.12         17.75         16.71         2 % 

Electricity

    $  Cdn/MWh         54         55         54         (2 )% 

 

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

Outlook for 2014

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

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

Corporate expenses

RESTRUCTURING

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

 

30     CAMECO CORPORATION

ADMINISTRATION

 

($ MILLIONS)

    2013      2012      CHANGE  

Direct administration

      160         163         (2 )% 

Restructuring

      5         —           —     

Stock-based compensation

      20         18         11 % 
  

 

 

     

 

 

     

 

 

  

Total administration

      185         181         2 % 
  

 

 

     

 

 

     

 

 

  

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

 

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

 

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

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

Outlook for 2014

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

EXPLORATION

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

Outlook for 2014

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

 

•   decreased activities in Australia

 

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

FINANCE COSTS

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

FINANCE INCOME

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

GAINS AND LOSSES ON DERIVATIVES

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

INCOME TAXES

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    31

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

 

($ MILLIONS)

    2013     2012  

Pre-tax adjusted earnings1

     

Canada2

      (466 )      (320 ) 

Foreign2

      849        706   
  

 

 

    

 

 

  

Total pre-tax adjusted earnings

      383        386   
  

 

 

    

 

 

  

Adjusted income taxes1

     

Canada2

      (94 )      (74 ) 

Foreign

      33        28   
  

 

 

    

 

 

  

Adjusted income tax expense (recovery)

      (61 )      (46 ) 
  

 

 

    

 

 

  

Effective tax rate

      (16 )%      (12 )% 

 

1  Pre-tax adjusted earnings and adjusted income taxes are non-IFRS measures.
2 Our IFRS-based measures have been adjusted by the amounts reflected in the table in adjusted net earnings (non-IFRS measure on page 28).

CRA DISCLOSURE

Since 2008, the Canada Revenue Agency (CRA) has disputed the offshore marketing company structure and related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2008 tax returns. We believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

Transfer pricing is a complex area of tax law, and it is difficult to predict the outcome of a case like ours as there are only a handful of reported court decisions on transfer pricing in Canada. However, tax authorities generally test two things:

 

•   the governance (structure)

 

•   the price

As the majority of our customers are located outside Canada, we established an offshore marketing subsidiary. This subsidiary entered into intercompany purchase and sales agreements as well as uranium supply agreements with third parties. We have arm’s-length transfer price arrangements in place, which expose both parties to the risks and the rewards accruing to them under this portfolio of purchase and sales contracts.

With respect to the contract prices, they are generally comparable to those established in sales contracts between arm’s-length buyers and sellers entered into at that time. We have recorded a cumulative tax provision of $73 million, where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 to 2013.

We are confident that we will be successful in our case; however, for the years 2003 through 2008, CRA issued notices of reassessment for approximately $2.0 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $590 million. The Canadian Income Tax Act includes provisions that require certain companies to pay 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions and tax loss carryovers, we have been required to pay a net amount of $103 million to CRA ($59 million as of December 31, 2013; $44 million in January 2014), which includes the amounts shown in the table below and described subsequently.

 

YEAR ($ MILLIONS)

    CASH
TAXES		      INTEREST AND
INSTALMENT
PENALTIES		      TRANSFER
PRICING
PENALTIES		      TOTAL  

Prior to 2013

      —           13         —           13   

2013

      1         9         36         46   

2014

      16         28         —           44   
  

 

 

     

 

 

     

 

 

     

 

 

  

Total

      17         50         36         103   
  

 

 

     

 

 

     

 

 

     

 

 

  

 

32     CAMECO CORPORATION

•   approximately $13 million for interest and instalment penalties paid prior to 2013. These amounts were not reported separately as they were not material in any given year.

 

•   approximately $27 million in January 2013, representing 50% of the amount owed for the amounts reassessed in December 2012—$20 million of this payment was refunded in the second quarter of 2013 when it was determined by CRA that they had reassessed amounts outside of the allowable review period

 

•   approximately $36 million in December 2013 that related to a $72 million transfer pricing penalty we were assessed for the 2007 taxation year. This was the first transfer pricing penalty assessed since CRA began to issue reassessments with respect to the transfer pricing dispute.

 

•   approximately $3 million paid in 2013. This amount would have been refundable in the year, but instead was applied as a credit against the amounts reassessed in December 2013 (for which a further payment was made in January 2014).

 

•   approximately $44 million in January 2014, representing 50% of the amount owed as reassessed in December 2013 and related to the 2008 taxation year

Using the methodology we believe CRA will continue to apply, and including the $2.0 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $5.7 billion in income as taxable in Canada for the years 2003 through 2013, which would result in a related tax expense of approximately $1.6 billion. As well, CRA may continue to apply transfer price penalties to taxation years subsequent to 2007. As a result, we estimate that cash taxes and transfer pricing penalties would be between $1.25 billion and $1.3 billion. In addition, we estimate there would be interest and instalment penalties applied that would be material to Cameco. We would be responsible for remitting 50% of the cash taxes and transfer pricing penalties (between $625 million and $650 million) plus related interest and instalment penalties assessed, which would be material to Cameco.

Under the Canadian federal and provincial tax legislation, the amount required to be remitted each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers; however, we expect it will generally follow the schedule in the table below.

 

DECEMBER 31, 2013 ($ MILLIONS)

    2003 – 2013      2014 – 2016      2017 – 2023      TOTAL  

50% of cash taxes and transfer pricing penalties payable in the period1

      37         250 – 275         325 – 350         625 – 650   

 

1 These amounts do not include interest and instalment penalties, which totaled approximately $22 million to December 31, 2013.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to CRA, including the $103 million already paid to date.

The case on the 2003 reassessment is expected to go to trial in 2015. If this timing is adhered to, we expect to have a Tax Court decision in 2015 or 2016.

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

This discussion of our expectations relating to our tax dispute with CRA and future tax reassessments by CRA, including the amounts of future additional taxable income, additional tax expense, cash taxes payable, transfer pricing penalties, and interest and possible instalment penalties thereon and related remittances, and timing of a Tax Court decision, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 2 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.

Assumptions

 

•   CRA will reassess us for the years 2009 through 2013 using a similar methodology as for the years 2003 through 2008, with the time lag for the reassessments for each year being similar to what has occurred to date

 

•   we will be able to apply elective deductions and tax loss carryovers to the extent anticipated

 

•   CRA will seek to impose transfer pricing penalties (10% of the income adjustment) in addition to interest charges and instalment penalties
•   we will be substantially successful in our dispute with CRA and the cumulative tax provision of $73 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date
 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    33

Material risks that could cause actual results to differ materially

 

•   CRA reassesses us for years 2009 through 2013 using a different methodology than for years 2003 through 2008, or we are unable to utilize elective deductions and loss carryovers to the same extent as anticipated, resulting in the required cash payments to CRA pending the outcome of the dispute being higher than expected

 

•   the time lag for the reassessments for each year is different than for those to date
•   we are unsuccessful and the outcome of our dispute with CRA results in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision, which could have a material adverse effect on our liquidity, financial position, results of operations and cash flows

 

•   cash tax payable increases due to unanticipated adjustments by CRA not related to transfer pricing
 

 

Outlook for 2014

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

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

FOREIGN EXCHANGE

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

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

At December 31, 2013:

 

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

 

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

 

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

 

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

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

SENSITIVITY ANALYSIS

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

 

34     CAMECO CORPORATION

Outlook for 2014

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

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

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

2014 FINANCIAL OUTLOOK

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

 

    

CONSOLIDATED

   

URANIUM

   

FUEL SERVICES

   

NUKEM

Production

    —    23.8 to 24.3 million lbs    13 to 14 million kgU    —

Sales volume

    —    31 to 33 million lbs    Decrease 5% to 10%    9 to 11 million lbs U3O8

Revenue compared to 2013

    Increase 0% to 5%    Increase 0% to 5%1    Decrease 5% to 10%    Increase 0% to 5%

Average unit cost of sales

(including D&A)

    —    Increase 0% to 5%2    Increase 0% to 5%    Increase 0% to 5%

Direct administration costs compared to 20133

    Increase 0% to 5%    —    —    Increase 0% to 5%

Exploration costs compared to 2013

    —    Decrease 35% to 40%    —    —

Tax rate

    Recovery of 30% to 35%    —    —    Expense of 30% to 35%

Capital expenditures

    $495 million    —    —    —

 

1  Based on a uranium spot price of $35.50 (US) per pound (the Ux spot price as of February 3, 2014), a long-term price indicator of $50.00 (US) per pound (the Ux long-term indicator on January 27, 2014) and an exchange rate of $1.00 (US) for $1.03 (Cdn).
2  This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we make discretionary purchases in 2014 then we expect the overall unit cost of sales to increase further.
3  Direct administration costs do not include stock-based compensation expenses. See page 31 for more information.

SENSITIVITY ANALYSIS

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

Liquidity and capital resources

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

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    35

FINANCIAL CONDITION

 

     2013     2012  

Cash position ($ millions)

(cash, cash equivalents, short-term investments, less bank overdraft)

      188        799   

Cash provided by operations ($ millions)

(net cash flow generated by our operating activities after changes in working capital)

      530        579   

Cash provided by operations/net debt

(net debt is total consolidated debt, less cash position)

      46 %      103 % 

Net debt/total capitalization

(total capitalization is total long-term debt and equity)

      17 %      9 % 

CREDIT RATINGS

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

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

 

SECURITY

    DBRS      S&P  

Commercial paper

      R-1 (low)         A-1 (low)1   

Senior unsecured debentures

      A (low)         BBB+   

 

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

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

Liquidity

 

($ MILLIONS)

    2013     2012  

Cash, cash equivalents and short-term investments at beginning of year

      799        1,202   

Cash from operations

      530        579   

Investment activities

     

Additions to property, plant and equipment and acquisitions

      (898 )      (1,248 ) 

Other investing activities

      (6 )      (23 ) 

Financing activities

     

Change in debt

      (18 )      485   

Interest paid

      (66 )      (44 ) 

Issue of shares

      2        7   

Dividends

      (158 )      (158 ) 

Exchange rate on changes on foreign currency cash balances

      3        (1 ) 

Cash, cash equivalents and short term investments, less bank overdraft at end of year

      188        799   

Cash from operations

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

Investing activities

Cash used in investing includes acquisitions and capital spending.

ACQUISITIONS AND DIVESTITURES

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

 

 

36     CAMECO CORPORATION

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

Under the agreements governing BPLP, the limited partners have rights of first offer upon a sale by us. Closing of the transaction is subject to completion or waiver of the right of first offer process by the other limited partners and receipt of certain regulatory approvals.

CAPITAL SPENDING

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

 

CAMECO’S SHARE ($ MILLIONS)

    2013 PLAN     2013 ACTUAL      2014 PLAN  

Sustaining capital

        

McArthur River/Key Lake

      55        64         30   

Cigar Lake

      —          —           15   

Rabbit Lake

      70        50         40   

US ISR

      5        5         5   

Inkai

      7        1         5   

Fuel services

      10        8         10   

Other

      23        9         10   
  

 

 

    

 

 

     

 

 

  

Total sustaining capital

      170        137         115   
  

 

 

    

 

 

     

 

 

  

Capacity replacement capital

        

McArthur River/Key Lake

      75        73         60   

Cigar Lake

      —          —           25   

Rabbit Lake

      5        3         15   

US ISR

      30        22         20   

Inkai

      20        16         15   
  

 

 

    

 

 

     

 

 

  

Total capacity replacement capital

      130        114         135   
  

 

 

    

 

 

     

 

 

  

Growth capital

        

McArthur River/Key Lake

      55        29         75   

US ISR

      30        33         10   

Millennium

      5        5         5   

Inkai

      21        9         5   

Cigar Lake

      260        284         145   

Fuel Services

      4        2         5   
  

 

 

    

 

 

     

 

 

  

Total growth capital

      375        362         245   
  

 

 

    

 

 

     

 

 

  

Talvivaara

      10        10         —     
  

 

 

    

 

 

     

 

 

  

Total uranium & fuel services

      685 1      623         495   
  

 

 

    

 

 

     

 

 

  

Electricity (our 31.6% share of BPLP)

      80        75         —     

 

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

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

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    37

OUTLOOK FOR INVESTING ACTIVITIES

 

(CAMECO’S SHARE IN $ MILLIONS)

    2015 PLAN      2016 PLAN  

Total uranium & fuel services

      400-450         500-550   
  

 

 

     

 

 

  

Sustaining capital

      160-175         220-240   

Capacity replacement capital

      150-170         165-175   

Growth capital

      90-105         115-135   

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

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

 

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

 

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

 

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

 

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

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

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

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

Financing activities

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

LONG-TERM CONTRACTUAL OBLIGATIONS

 

DECEMBER 31 ($ MILLIONS)

    2014      2015 AND
2016		      2017 AND
2018		      2019 AND
BEYOND		      TOTAL  

Long-term debt

      —           300         —           1,000         1,300   

Interest on long-term debt

      63         111         97         210         481   

Provision for reclamation

      18         71         65         669         823   

Provision for waste disposal

      2         4         5         7         18   

Other liabilities

      —           —           —           46         46   
  

 

 

     

 

 

     

 

 

     

 

 

     

 

 

  

Total

      83         486         167         1,932         2,668   
  

 

 

     

 

 

     

 

 

     

 

 

     

 

 

  

 

38     CAMECO CORPORATION

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

 

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

 

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

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

 

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

 

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

 

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

 

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

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

DEBT COVENANTS

Our revolving credit facility includes the following financial covenants:

 

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

 

•   other customary covenants and events of default

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

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

Off-balance sheet arrangements

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

 

•   purchase commitments

 

•   financial assurances

PURCHASE COMMITMENTS

 

DECEMBER 31 ($ MILLIONS)

    2014      2015 AND
2016		      2017 AND
2018		      2019 AND
BEYOND		      TOTAL  

Purchase commitments1

      352         583         109         164         1,208   

 

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

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

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

 

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

 

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

 

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    39

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

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

FINANCIAL ASSURANCES

 

DECEMBER 31 ($ MILLIONS)

    2013      2012      CHANGE  

Standby letters of credit

      791         672         18 % 

BPLP guarantees

      58         59         (2 )% 
  

 

 

     

 

 

     

 

 

  

Total

      849         731         16 % 
  

 

 

     

 

 

     

 

 

  

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

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

Balance sheet

 

DECEMBER 31

($ MILLIONS EXCEPT PER SHARE AMOUNTS)

    2013      2012      20111      CHANGE FROM
2012 TO 2013		  

Inventory

      913         564         494         62 % 

Total assets

      8,039         7,431         7,616         8 % 

Long-term financial liabilities

      1,915         1,903         1,736         1 % 

Dividends per common share

      0.40         0.40         0.40         —     

 

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

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

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

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

 

 

40     CAMECO CORPORATION

2013 financial results by segment

Uranium

 

HIGHLIGHTS

    2013      2012      CHANGE  

Production volume (million lbs)

      23.6         21.9         8 % 

Sales volume (million lbs)

      32.8         32.9         —     

Average spot price ($US/lb)

      38.17         48.40         (21 )% 

Average long-term price ($US/lb)

      54.13         60.13         (10 )% 

Average realized price

         

($US/lb)

      48.35         47.72         1 % 

($Cdn/lb)

      49.81         47.72         4 % 

Average unit cost of sales ($Cdn/lb) (including D&A)

      33.01         32.09         3 % 

Revenue ($ millions)

      1,633         1,571         4 % 

Gross profit ($ millions)

      550         514         7 % 

Gross profit (%)

      34         33         3 % 

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

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

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

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

 

($CDN/LB)

    2013      2012      CHANGE  

Produced

         

Cash cost

      18.37         19.95         (8 )% 

Non-cash cost

      9.46         8.13         16 % 
  

 

 

     

 

 

     

 

 

  

Total production cost

      27.83         28.08         (1 )% 
  

 

 

     

 

 

     

 

 

  

Quantity produced (million lbs)

      23.6         21.9         8 % 

Purchased

         

Cash cost

      27.95         28.50         (2 )% 

Quantity purchased (million lbs)

      13.2         11.2         18 % 

Totals

         

Produced and purchased costs

      27.87         28.22         (1 )% 

Quantities produced and purchased (million lbs)

      36.8         33.1         11 % 

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

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

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    41

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

CASH AND TOTAL COST PER POUND RECONCILIATION

 

($ MILLIONS)

    2013     2012  

Cost of product sold

      869.1        883.7   

Add / (subtract)

     

Royalties

      (90.8 )      (116.0 ) 

Standby charges

      (37.4 )      (28.6 ) 

Other selling costs

      (1.4 )      (6.2 ) 

Change in inventories

      63.1        23.1   
  

 

 

    

 

 

  

Cash operating costs (a)

      802.6        756.0   

Add / (subtract)

     

Depreciation and amortization

      212.9        172.9   

Change in inventories

      10.1        5.2   
  

 

 

    

 

 

  

Total operating costs (b)

      1,025.6        934.1   
  

 

 

    

 

 

  

Uranium produced and purchased (millions lbs) (c)

      36.8        33.1   
  

 

 

    

 

 

  

Cash costs per pound (a ÷ c)

      21.81        22.84   
  

 

 

    

 

 

  

Total costs per pound (b ÷ c)

      27.87        28.22   
  

 

 

    

 

 

  

Outlook for 2014

We expect to produce 23.8 million to 24.3 million pounds in 2014 and have commitments under long-term contracts to purchase approximately 2 million pounds.

Based on the contracts we have in place, we expect to deliver between 31 million and 33 million pounds of U3O8 in 2014. We expect the unit cost of sales to be up to 5% higher than in 2013, primarily due to higher costs for produced material. In 2014, we will complete a number of capital projects at our various production facilities, including Cigar Lake. Upon completion, we will begin to depreciate the assets, which will increase the non-cash portion of our production costs. In addition, until Cigar Lake ramps up to full production, the cash cost of material produced from the mine will initially be higher. If we make additional discretionary purchases in 2014, then we expect the overall unit cost of sales to increase further.

Based on current spot prices, revenue should be up to 5% higher than it was in 2013 as a result of an expected increase in the realized price.

PRICE SENSITIVITY ANALYSIS: URANIUM

The table and graph below are not forecasts of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table and graph. They are designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2013 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on December 31, 2013, and none of the assumptions we list below change.

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

 

42     CAMECO CORPORATION

Expected realized uranium price sensitivity under various spot price assumptions

(rounded to the nearest $1.00)

 

SPOT PRICES

($US/LB U3O8)

    $20      $40      $60      $80      $100      $120      $140  

2014

      45         48         55         62         69         76         81   

2015

      41         46         55         65         75         84         93   

2016

      42         47         57         68         78         88         96   

2017

      42         47         57         67         77         86         93   

2018

      43         49         58         68         78         86         93   

 

LOGO

The table and graph illustrate the mix of long-term contracts in our December 31, 2013 portfolio, and are consistent with our marketing strategy. Both have been updated to reflect deliveries made and contracts entered into up to December 31, 2013.

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

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

 

Sales

 

•   sales volumes on average of 30 million pounds per year, with commitment levels through 2016 higher than in 2017 and 2018

Deliveries

 

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

 

•   we defer a portion of deliveries under existing contracts for 2014

Annual inflation

 

•   is 1.5% in Canada and 2% in the US

Prices

 

•   the average long-term price indicator is the same as the average spot price for the entire year (a simplified approach for this purpose only). Since 1996, the long-term price indicator has averaged 17% higher than the spot price. This differential has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table and graph will be higher.
 

 

ROYALTIES

On January 3, 2014, the government of Saskatchewan released regulations to implement the changes to the Saskatchewan uranium royalty system originally announced in the 2013 provincial budget.

The government has changed tiered royalties from a revenue-based system to a modified profit-based system, retroactive to January 1, 2013. Under the new system, a 10% royalty will be charged on profit up to and including $22/kg U3O8 ($9.98/lb), and a 15% royalty on profit in excess of $22/kg U3O8. Profit will be determined as revenue less certain operating, exploration, reclamation and capital costs (applied to Saskatchewan uranium production). Under the new system, both exploration and capital costs will be deductible at the discretion of the producer.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    43

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

Also, as previously reported, the net basic royalty (basic royalty of 5% less the Saskatchewan resource credit) increased from 4.0% to 4.25% effective April 1, 2013. Other than the increase of the rate, there were no changes to the determination of the basic royalty, which continues to be levied by the province on the gross revenue from the sales of Saskatchewan uranium production.

Fuel services

(includes results for UF6, UO2 and fuel fabrication)

 

HIGHLIGHTS

    2013      2012      CHANGE  

Production volume (million kgU)

      14.9         14.2         5 % 

Sales volume (million kgU)

      17.6         16.4         7 % 

Realized price ($Cdn/kgU)

      18.12         17.75         2 % 

Average unit cost of sales ($Cdn/kgU) (including D&A)

      15.16         15.24         (1 )% 

Revenue ($ millions)

      319         291         10 % 

Gross profit ($ millions)

      52         41         27 % 

Gross profit (%)

      16         14         14 % 

Total revenue increased by 10% due to a 7% increase in sales volumes and a 2% increase in the realized price.

The total cost of products and services sold (including D&A) increased by 7% ($267 million compared to $250 million in 2012) due to the increase in sales volumes.

The net effect was an $11 million increase in gross profit.

Outlook for 2014

In 2014, we plan to produce 13 million to 14 million kgU, and we expect sales volumes to be 5% to 10% lower than in 2013. Overall revenue is expected to decrease by 5% to 10% as a result of the lower sales volumes. We expect the unit cost of product sold (including D&A) to increase by 0% to 5%; therefore, overall gross profit will decrease as a result.

NUKEM

 

($ MILLIONS EXCEPT WHERE INDICATED)

    2013        
   NUKEM     PURCHASE
ACCOUNTING		     CONSOLIDATED  

Uranium sales (million lbs)

      8.9        —          8.9   

Revenue

      503        (38 )      465   

Cost of product sold

(including D&A)

      420        25        445   

Gross profit (loss)

      83        (63 )      20   

Net earnings (loss)

      50        (43 )      7   

Adjustments on derivatives1

      (3 )      —          (3 ) 

NUKEM inventory write-down

      —          10        10   

Adjusted net earnings1

      47        (33 )      14   

Cash provided by operations

      6        —          6   

 

1  Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (non-IFRS measure, see page 28).

On January 9, 2013, we acquired NUKEM for cash consideration of €107 million ($140 million (US)). We also assumed NUKEM’s net debt, which amounted to about €79 million ($104 million (US)).

 

44     CAMECO CORPORATION

In accordance with the purchase agreement, we paid Advent additional consideration of €6,075,000 ($7,808,000), representing a share of NUKEM’s 2012 earnings. There will be no additional payments to Advent related to the transaction.

For accounting purposes, the purchase price is allocated to the assets and liabilities acquired based on their fair values as of the acquisition date. The purchase price allocation is provided in the table below.

Much of the purchase price was related to nuclear fuel inventories and the portfolio of sales and purchase contracts acquired. The amounts attributed to inventory and contracts were based on market values as at the acquisition date. They will be charged to earnings in the period(s) in which related transactions occur. The amount categorized as goodwill reflects the value assigned to the expected future earnings capabilities of the organization. This is the earnings potential that we anticipate will be realized through new business arrangements. Goodwill is not amortized and is tested for impairment at least annually.

PURCHASE PRICE ALLOCATION

 

($US MILLIONS)

       

Net assets

   

Working capital

      (22 ) 

Inventory

      165   

Sales, purchase contracts and other intangibles

      88   

Goodwill

      88   

Debt

      (117 ) 

Deferred taxes

      (54 ) 
  

 

 

  

Net assets acquired

      148   
  

 

 

  

Financed by

   

Cash

      140   

Additional consideration (earn-out provision)

      8   
  

 

 

  

Liabilities and equity

      148   
  

 

 

  

During 2013, NUKEM delivered 8.9 million pounds of uranium. On a consolidated basis, NUKEM contributed $465 million in revenues and $20 million in gross profit. Adjusted net earnings were $14 million (non-IFRS measure, see page 28). NUKEM’s contribution to our earnings is significantly impacted by our purchase price accounting. Excluding the impact of the purchase accounting, NUKEM’s adjusted net earnings (non-IFRS measure, see page 28) were $47 million for the year. NUKEM’s operating activities provided $6 million in cash during 2013 compared to our expectation of $50 million to $70 million. During the fourth quarter, we concluded a product purchase that had previously been planned for early 2014, reducing our reported cash flows for 2013 by approximately $55 million.

Uranium to be purchased under contractual fixed price arrangements and inventory on hand at the acquisition date were valued using the spot price at that time. The decline in the spot price in recent months has caused the carrying values of certain quantities to exceed their estimated realizable value, and we recorded an initial charge of $17 million ($11 million net of tax) and a subsequent recovery of $3 million ($1 million net of tax).

As noted above, much of the NUKEM purchase price was attributable to inventories and the portfolio of contracts. With respect to nuclear fuel inventories, amounts assigned were based on market values as of the date of acquisition. As these quantities are delivered to NUKEM’s customers, we will adjust the cost of product sold to reflect the values at the acquisition date, regardless of NUKEM’s historic costs.

As of the date of the purchase agreement, had NUKEM’s sales and purchase contracts been settled, it would have realized significant financial benefit. As a result, we paid a premium to acquire the portfolio. Accordingly, a portion of the purchase price has been attributed to the various contracts. In our accounting for NUKEM, we will amortize the amounts assigned to the portfolio in the periods in which NUKEM transacts under the relevant contracts. The net effect is a reduction in reported profit margins relative to NUKEM’s results. We expect the majority of the amount allocated to the contract portfolio will be amortized within two years.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    45

Outlook for 2014

For 2014, NUKEM expects to deliver between 9 million and 11 million pounds of uranium, resulting in an increase in total revenues of up to 5% compared to 2013. NUKEM expects to incur administration costs similar to 2013. The effective income tax rate is expected to remain in the range of 30% to 35%.

Electricity

BPLP (100% – not prorated to reflect our 31.6% interest)

 

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)

    2013     2012     CHANGE  

Output—terawatt hours (TWh)

      24.8        26.8        (7 )% 

Capacity factor

(the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)

      87 %      94 %      (7 )% 

Realized price ($/MWh)

      54 1      55 2      (2 )% 

Average Ontario electricity spot price ($/MWh)

      25        23        9 % 

Revenue

      1,370        1,487        (8 )% 

Operating costs (net of cost recoveries)

      1,001        945        6 % 

Cash costs

      777        724        7 % 

Non-cash costs

      224        221        1 % 

Income before interest and finance charges

      369        542        (32 )% 

Interest and finance charges

      8        26        (69 )% 

Cash from operations

      649        523        24 % 

Capital expenditures

      237        194        22 % 

Distributions

      330        425        (22 )% 

Capital calls

      42        63        (33 )% 

 

1 Based on actual generation of 24.8 TWh plus deemed generation of 0.6 TWh
2 Based on actual generation of 26.8 TWh plus deemed generation of 0.4 TWh

OUR EARNINGS FROM BPLP

 

HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)

    2013     2012     CHANGE  

BPLP’s earnings before taxes (100%)

      361        516        (30 )% 

Cameco’s share of pretax earnings before adjustments (31.6%)

      114        163        (30 )% 

Proprietary adjustments

      (5 )      (6 )      (17 )% 

Earnings before taxes from BPLP

      109        157        (31 )% 

BPLP’s decreased results in 2013 when compared to 2012 are partially the result of revenues being 8% lower than in 2012 due to a 7% decrease in generation and a 2% decrease in realized electricity prices. BPLP’s average realized price reflects spot sales, revenue recognized under BPLP’s agreement with the Ontario Power Authority (OPA) and revenue from financial contracts.

BPLP has an agreement with the OPA under which output from each B reactor is supported by a floor price (currently $52.34/MWh) that is adjusted annually for inflation. The floor price mechanism and any associated payments to BPLP for the output from each individual B reactor will expire on a date specified in the agreement. The expiry dates are June 30, 2019 for unit B5, April 30, 2020 for unit B6, August 31, 2020 for unit B7 and December 31, 2020 for unit B8. Revenue is recognized monthly, based on the positive difference between the floor price and the spot price. BPLP does not have to repay the revenue from the agreement with the OPA to the extent that the floor price for the particular year exceeds the average spot price for that year.

The agreement also provides for payment if the Independent Electricity System Operator (IESO) reduces BPLP’s generation because Ontario’s baseload generation supply is higher than required. The amount of the reduction is considered ‘deemed generation’, for which BPLP is paid either the spot price or the floor price—whichever is higher. The compensation for deemed generation is a reflection of the Bruce B units’ ability to provide flexible output to the Ontario market, and the relatively high fixed cost nature of the business. Deemed generation was 0.6 TWh in 2013 and 0.4 TWh in 2012.

 

46     CAMECO CORPORATION

During 2013, BPLP recognized revenue of $698 million under the agreement with the OPA, compared to $773 million in 2012.

BPLP also has financial contracts in place that reflect market conditions at the time they were signed. BPLP receives or pays the difference between the contract price and the spot price. During 2013, gains on BPLP’s contracting activity were $59 million, compared to $108 million in 2012.

BPLP’s capacity factor was 87% in 2013, down from 94% in 2012 due to a higher volume of outage days during the year. In 2013, there were 140 planned and 20 unplanned outage days, compared to 46 planned and 25 unplanned outage days in 2012.

In addition, BPLP’s decreased results in 2013 when compared to 2012 were also partially the result of higher operating costs. BPLP’s operating costs were $1.0 billion this year compared to $945 million in 2012 due to higher maintenance costs incurred primarily as a result of more planned outage days than in 2012.

The net effect was a decrease in our share of earnings before taxes of 31%.

BPLP distributed $330 million to the partners in 2013. Our share was $104 million. BPLP capital calls to the partners in 2013 were $42 million. Our share was $13 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

Subject to closing, we have sold our entire interest in BPLP and related entities effective December 31, 2013. See Acquisitions and divestitures on page 36 for details.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    47

Fourth quarter results

Fourth quarter consolidated results

 

HIGHLIGHTS

($ MILLIONS EXCEPT WHERE INDICATED)

    THREE MONTHS ENDED
DECEMBER 31		      CHANGE  
   2013      2012     

Revenue

      977         846         15 % 

Gross profit

      185         255         (27 )% 

Net earnings attributable to equity holders

      64         41         56 % 

$ per common share (basic)

      0.16         0.10         60 % 

$ per common share (diluted)

      0.16         0.10         60 % 

Adjusted net earnings (non-IFRS, see page 28)

      150         233         (36 )% 

$ per common share (adjusted and diluted)

      0.38         0.59         (36 )% 

Cash provided by operations (after working capital changes)

      154         286         (46 )% 

NET EARNINGS

In the fourth quarter of 2013, our net earnings were $64 million ($0.16 per share diluted), an increase of $23 million compared to $41 million ($0.10 per share diluted) in 2012, mainly due to:

 

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

 

•   lower exploration and administrative expenditures

 

•   higher income tax recovery

offset by:

 

•   lower uranium gross profits due to lower sales volumes and higher average unit cost of sales

 

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

 

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

On an adjusted basis, our earnings this quarter were $150 million ($0.38 per share diluted) compared to $233 million ($0.59 per share diluted) (non-IFRS measure, see below) in the fourth quarter of 2012, mainly due to:

 

•   lower uranium gross profits due to lower sales volumes and higher average unit cost of sales

offset by:

 

•   lower exploration and administrative expenditures

 

•   higher income tax recovery

We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our financial performance from period to period. See page 28 for more information. The table below reconciles adjusted net earnings with our net earnings.

 

($ MILLIONS)

    THREE MONTHS ENDED
DECEMBER 31		  
   2013     2012  

Net earnings attributable to equity holders

      64        41   

Adjustments

     

Adjustments on derivatives1 (pre-tax)

      36        33   

NUKEM inventory write-down recovery

      (3 )      —     

Impairment on Talvivaara asset

      70        —     

Impairment on non-producing property

      —          168   

Income taxes on adjustments

      (17 )      (9 ) 
  

 

 

    

 

 

  

Adjusted net earnings

      150        233   
  

 

 

    

 

 

  

 

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

 

48     CAMECO CORPORATION

ADMINISTRATION

As a result of restructuring activities, direct administration costs were $45 million in the quarter, $8 million lower than the same period last year. Stock-based compensation expenses were $2 million higher than the fourth quarter of 2012. See note 27 to the financial statements.

 

($ MILLIONS)

    THREE MONTHS ENDED
DECEMBER 31		      CHANGE  
   2013      2012     

Direct administration

      45         53         (15 )% 

Stock-based compensation

      6         4         50 % 
  

 

 

     

 

 

     

 

 

  

Total administration

      51         57         (11 )% 
  

 

 

     

 

 

     

 

 

  

Quarterly trends

 

HIGHLIGHTS

($ MILLIONS EXCEPT PER SHARE AMOUNTS)

    2013      2012  
   Q4      Q3      Q2     Q1      Q41      Q31      Q21     Q11  

Revenue

      977         597         421        444         846         296         282        467   

Net earnings attributable to equity holders

      64         211         34        9         41         79         5        128   

$ per common share (basic)

      0.16         0.53         0.09        0.03         0.10         0.20         0.01        0.33   

$ per common share (diluted)

      0.16         0.53         0.09        0.03         0.10         0.20         0.01        0.33   

Adjusted net earnings (non-IFRS, see page 28)

      150         208         61        26         233         49         31        121   

$ per common share (adjusted and diluted)

      0.38         0.53         0.14        0.07         0.59         0.12         0.08        0.31   

Cash provided by operations (after working capital changes)

      162         136         (37 )      269         286         36         (117 )      374   

 

1  Our quarterly results have been revised in accordance with IFRS 11 – Joint Arrangements and IAS 19 – Employee Benefits.

Key things to note:

 

•   Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 65% of consolidated revenues in the fourth quarter of 2013 and 74% of consolidated revenues in the fourth quarter of 2012

 

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

 

•   Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our results from period to period (see page 28 for more information).

 

•   Cash from operations tends to fluctuate as a result of the timing of deliveries and product purchases in our uranium and fuel services segments.

 

•   Quarterly results are not necessarily a good indication of annual results due to the variability in customer requirements noted above.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    49

Fourth quarter results by segment

Uranium

 

HIGHLIGHTS

    THREE MONTHS ENDED
DECEMBER 31		      CHANGE  
   2013      2012     

Production volume (million lbs)

      7.5         6.5         15 % 
  

 

 

     

 

 

     

 

 

  

Sales volume (million lbs)

      12.7         14.5         (12 )% 
  

 

 

     

 

 

     

 

 

  

Average spot price ($US/lb)

      35.03         42.46         (17 )% 

Average long-term price ($US/lb)

      50.00         58.50         (15 )% 

Average realized price

         

($US/lb)

      47.76         49.97         (4 )% 

($Cdn/lb)

      49.80         49.37         1 % 
  

 

 

     

 

 

     

 

 

  

Average unit cost of sales ($Cdn/lb) (including D&A)

      37.94         32.85         15 % 
  

 

 

     

 

 

     

 

 

  

Revenue ($ millions)

      631         716         (12 )% 
  

 

 

     

 

 

     

 

 

  

Gross profit ($ millions)

      150         240         (38 )% 
  

 

 

     

 

 

     

 

 

  

Gross profit (%)

      24         34         (29 )% 
  

 

 

     

 

 

     

 

 

  

Production volumes this quarter were 15% higher compared to the fourth quarter of 2012, mainly due to higher production at McArthur River/Key Lake, Rabbit Lake, Inkai, and Smith-Ranch Highland with the rampup of the North Butte satellite operation. See Our operations and projects starting on page 54 for more information.

Uranium revenues were down 12% due to a 12% decrease in sales volumes, which represents normal quarterly variance in our delivery schedule.

The average realized price increased slightly compared to 2012 despite a 17% drop in the spot price, due to the mix of contract deliveries, higher US dollar prices under fixed price contracts, and the effect of foreign exchange. In the fourth quarter of 2013, our realized foreign exchange rate was $1.04 compared to $0.99 in the prior year.

Total cost of sales (including D&A) increased by 1% ($481 million compared to $476 million in 2012). This was mainly the result of a 15% increase in the average unit cost of sales, offset by a 12% decrease in sales volumes.

The unit cost of sales increased due to an increase in the non-cash costs of produced material in the fourth quarter compared to the same period in 2012, and an increase in the unit cost of material purchased.

In 2013, we purchased about 10 million pounds of material under the Russian HEU commercial agreement, more than the annual 7 million historically purchased. Some of this additional material was made available under an option in the agreement, which we exercised in 2006. Under the agreement, pricing of this option material was at a discount to spot prices at the time of delivery. We received the option material in the fourth quarter as our final purchase under the Russian HEU commercial agreement.

In addition, in the fourth quarter, we had back-to-back purchase and sale arrangements that, while profitable, required we purchase material at a price higher than the current spot price.

The net effect was a $90 million decrease in gross profit for the quarter.

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

 

50     CAMECO CORPORATION

($/LB)

    THREE MONTHS ENDED
DECEMBER 31		      CHANGE  
   2013      2012     

Produced

         

Cash cost

      15.61         17.01         (8) % 

Non-cash cost

      9.42         8.41         12 % 
  

 

 

     

 

 

     

 

 

  

Total production cost

      25.03         25.42         (2) % 
  

 

 

     

 

 

     

 

 

  

Quantity produced (million lbs)

      7.5         6.5         15 % 
  

 

 

     

 

 

     

 

 

  

Purchased

         

Cash cost

      37.26         32.94         13 % 
  

 

 

     

 

 

     

 

 

  

Quantity purchased (million lbs)

      4.4         2.8         57 % 
  

 

 

     

 

 

     

 

 

  

Totals

         

Produced and purchased costs

      29.55         27.69         7 % 
  

 

 

     

 

 

     

 

 

  

Quantities produced and purchased (million lbs)

      11.9         9.3         28 % 
  

 

 

     

 

 

     

 

 

  

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

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

To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the fourth quarters of 2013 and 2012.

CASH AND TOTAL COST PER POUND RECONCILIATION

 

($ MILLIONS)

    THREE MONTHS ENDED
DECEMBER 31		      CHANGE  
   2013      2012     

Cost of product sold

      359.8         394.4         (9) % 

Add / (subtract)

         

Royalties

      (52.5)         (51.7)         2 % 

Standby charges

      (11.1)         (7.7)         44 % 

Other selling costs

      (4.8)         (3.3)         45 % 

Change in inventories

      (10.3)         (128.9)         (92) % 
  

 

 

     

 

 

     

 

 

  

Cash operating costs (a)

      281.1         202.8         39 % 

Add / (subtract)

         

Depreciation and amortization

      121.2         82.1         48 % 

Change in inventories

      (50.7)         (27.4)         85 % 
  

 

 

     

 

 

     

 

 

  

Total operating costs (b)

      351.6         257.5         37 % 
  

 

 

     

 

 

     

 

 

  

Uranium produced & purchased (millions lbs) (c)

      11.9         9.3         28 % 
  

 

 

     

 

 

     

 

 

  

Cash costs ($/lb) (a ÷ c)

      23.62         21.81         8 % 

Total costs ($/lb) (b ÷ c)

      29.55         27.69         7 % 
  

 

 

     

 

 

     

 

 

  

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    51

Fuel services

(includes results for UF6, UO2 and fuel fabrication)

 

HIGHLIGHTS

    THREE MONTHS ENDED
DECEMBER 31		      CHANGE  
   2013      2012     

Production volume (million kgU)

      2.7         3.3         (18) % 

Sales volume (million kgU)

      6.5         6.0         8 % 

Average realized price ($Cdn/kgU)

      17.24         17.16         —     

Average unit cost of sales ($Cdn/kgU) (including D&A)

      14.42         14.06         3 % 

Revenue ($ millions)

      112         103         9 % 

Gross profit ($ millions)

      18         19         (5) % 

Gross profit (%)

      16         18         (11) % 

Total revenue increased by 9% due to an 8% increase in sales volumes.

The total cost of sales (including D&A) increased by 9% ($93 million compared to $85 million in the fourth quarter of 2012) mainly due to an 8% increase in sales volumes.

The net effect was a $1 million decrease in gross profit.

NUKEM

 

($ MILLIONS EXCEPT WHERE INDICATED)

    THREE MONTHS ENDED
DECEMBER 31, 2013		     CONSOLIDATED  
   NUKEM     PURCHASE
ACCOUNTING		    

Uranium sales (million lbs)

      3.3        —          3.3   

Revenue

      220        (32 )      188   

Cost of product sold

(including D&A)

      202        (33 )      169   

Gross profit

      18        1        19   

Net earnings

      12        1        13   

Adjustments on derivatives1

      (1 )      —          (1 ) 

NUKEM inventory write-down

      —          (1 )      (1 ) 

Adjusted net earnings1

      11        —          11   

Cash provided by operations

      9        —          9   

 

1  Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (non-IFRS measure, see page 28).

During the fourth quarter of 2013, NUKEM delivered 3.3 million pounds of uranium. On a consolidated basis, NUKEM contributed $188 million in revenues and gross profit of $19 million. Adjusted net earnings were $11 million (non-IFRS measure, see page 28). During the quarter, NUKEM’s operating activities provided $9 million in cash, which was lower than expected due to the timing of a product purchase that was originally planned for early 2014 occurring in December of 2013.

 

52     CAMECO CORPORATION

Electricity

BPLP (100% – not prorated to reflect our 31.6% interest)

 

HIGHLIGHTS

($ MILLIONS EXCEPT WHERE INDICATED)

    THREE MONTHS ENDED
DECEMBER 31		     CHANGE  
   2013     2012    

Output—terawatt hours (TWh)

      6.9        7.2        (4 )% 

Capacity factor

(the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)

      96 %      100 %      (4 )% 

Realized price ($/MWh)

      54 1      54        —     

Average Ontario electricity spot price ($/MWh)

      22        24        (8 )% 

Revenue

      383        393        (3 )% 

Operating costs (net of cost recoveries)

      234        236        (1 )% 

Cash costs

      173        179        (3 )% 

Non-cash costs

      61        57        7 % 

Income before interest and finance charges

      149        157        (5 )% 

Interest and finance charges

      (4 )      6        (167 )% 

Cash from operations

      181        100        81 % 

Capital expenditures

      56        54        4 % 

Distributions

      125        140        (11 )% 

Capital calls

      15        14        7 % 

 

1  Based on actual generation of 6.9 TWh plus deemed generation of 0.2 TWh in the fourth quarter of 2013.

OUR EARNINGS FROM BPLP

 

HIGHLIGHTS

($ MILLIONS EXCEPT WHERE INDICATED)

    THREE MONTHS ENDED
DECEMBER 31		     CHANGE  
   2013     2012    

BPLP’s earnings before taxes (100%)

      153        151        1 % 

Cameco’s share of pretax earnings before adjustments (31.6%)

      48        48        —     

Proprietary adjustments

      (1 )      (2 )      (50 )% 

Earnings before taxes from BPLP

      47        46        2 % 

Total electricity revenue decreased 3% this quarter due to a lower output. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA, and financial contract revenue. BPLP recognized revenue of $212 million this quarter under its agreement with the OPA, compared to $198 million in the fourth quarter of 2012. Gains on BPLP’s contract activity in the fourth quarter of 2013 were $17 million, compared to $22 million in the fourth quarter of 2012.

The capacity factor was 96% this quarter, down from 100% in the fourth quarter of 2012. There were seven unplanned outage days in the quarter, compared to no outage days in the fourth quarter of 2012.

Operating costs this quarter of $234 million were similar to the $236 million in 2012.

The result was $47 million in earnings before taxes (our share) in the fourth quarter of 2013 compared to $46 million in earnings before taxes in the fourth quarter of 2012.

BPLP distributed $125 million to the partners in the fourth quarter. Our share was $40 million. BPLP capital calls to the partners in the fourth quarter were $15 million. Our share was $5 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    53

Our operations and projects

This section of our MD&A is an overview of each of our operations, what we accomplished this year, our plans for the future and how we manage risk.

 

57    URANIUM – PRODUCTION OVERVIEW
57   

OUTLOOK

58    URANIUM OPERATING PROPERTIES
58   

MCARTHUR RIVER / KEY LAKE

64   

RABBIT LAKE

66   

SMITH RANCH-HIGHLAND

67   

CROW BUTTE

68   

INKAI

71    URANIUM – DEVELOPMENT PROJECT
71   

CIGAR LAKE

76    URANIUM – PROJECTS UNDER EVALUATION
76   

MILLENNIUM

76   

YEELIRRIE

77   

KINTYRE

78    URANIUM – EXPLORATION AND CORPORATE DEVELOPMENT
80    FUEL SERVICES – REFINING, CONVERSION AND FUEL MANUFACTURING
80   

BLIND RIVER REFINERY

81   

PORT HOPE CONVERSION SERVICES

81   

CAMECO FUEL MANUFACTURING INC. (CFM)

81   

SPRINGFIELDS FUELS LTD. (SFL)

83    NUKEM GMB

 

54     CAMECO CORPORATION

Managing the risks

The nature of our operations means we face many potential risks and hazards that could have a significant impact on our business. We have comprehensive systems and procedures in place to manage them, but there is no assurance we will be successful in preventing the harm any of these risks and hazards could cause.

Below we list the regulatory, environmental and operational risks that generally apply to all of our operations, development project and projects under evaluation. We also talk about how we manage specific risks in each operation or project update. These risks could have a material impact on our business in the near term.

We recommend you also review our annual information form, which includes a discussion of other material risks that could have an impact on our business.

Regulatory risks

A significant part of our economic value depends on our ability to:

 

•   obtain and renew the licences and other approvals we need to operate, to increase production at our mines and to develop new mines. If we do not receive the regulatory approvals we need, or do not receive them at the right time, then we may have to delay, modify or cancel a project, which could increase our costs and delay or prevent us from generating revenue from the project. Regulatory review, including the review of environmental matters, is a long and complex process.

 

•   comply with the conditions in these licences and approvals. In a number of instances, our right to continue operating facilities, increase production at our mines and develop new mines depends on our compliance with these conditions.

 

•   comply with the extensive and complex laws and regulations that govern our activities, including our growth plans. Environmental legislation imposes strict standards and controls on almost every aspect of our operations and the mines we plan to develop, and is not only introducing new requirements, but also becoming more stringent. For example:

 

•   we must complete the environmental assessment process before we can begin developing a new mine or make any significant change to our operations

 

•   we may need regulatory approval to make changes to our operational processes, which can take a significant amount of time because it may require an extensive review of supporting technical information. The complexity of this process can be further compounded when regulatory approvals are required from multiple agencies.

We use significant management and financial resources to manage our regulatory risks.

Environmental risks

We have the safety, health and environmental risks associated with any mining and chemical processing company. Our uranium and fuel services segments also face unique risks associated with radiation.

Laws to protect the environment are becoming more stringent for members of the nuclear energy industry and have inter-jurisdictional aspects (both federal and provincial/state regimes are applicable). Once we have permanently stopped mining and processing activities at an operating site, we are required to decommission the site to the satisfaction of the regulators. We have developed conceptual decommissioning plans for our operating sites and use them to estimate our decommissioning costs. Regulators review our conceptual decommissioning plan on a regular basis. As the site approaches or goes into decommissioning, regulators review the detailed decommissioning plans. This can result in further regulatory process, as well as additional requirements, costs and financial assurances.

At the end of 2013, our estimate of total decommissioning and reclamation costs was $823 million. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $574 million at the end of 2013 (the present value of the $823 million). Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, our expected costs for decommissioning and reclamation for the next five years are not material.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    55

We provide financial assurances for decommissioning and reclamation such as letters of credit to regulatory authorities, as required. We had a total of $768 million in letters of credit supporting our reclamation liabilities at the end of 2013. All of our North American operations have letters of credit in place that provide financial assurance in connection with our preliminary plans for decommissioning for the sites.

Some of the sites we own or operate have been under ongoing investigation and/or remediation and planning as a result of historic soil and groundwater conditions. For example, we are addressing issues related to historic soil and groundwater contamination at Port Hope.

We use significant management and financial resources to manage our environmental risks.

We manage environmental risks through our safety, health, environment and quality (SHEQ) management system. Our chief executive officer is responsible for ensuring that our SHEQ management system is implemented. Our board’s safety, health and environment committee also oversees how we manage our environmental risks.

In 2013, we invested:

 

•   $108 million in environmental protection, monitoring and assessment programs, or 8% less than 2012 as a result of large capital projects nearing completion

 

•   $31 million in health and safety programs, or 3% more than 2012

Spending for health and safety programs in 2014 is expected to be similar to 2013, while spending for environmental programs is expected to decrease in-line with our planned reduction in capital spending.

Operational risks

Other operational risks and hazards include:

 

•     environmental damage

 

•     industrial and transportation accidents

 

•     labour shortages, disputes or strikes

 

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

 

•     shortages of required materials, supplies and equipment

 

•     transportation disruptions

 

•     electrical power interruptions

 

•     equipment failures

 

•     non-compliance with laws and licences

 

•     catastrophic accidents

   

•     fires

 

•     blockades or other acts of social or political activism

 

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

 

•     unusual, unexpected or adverse mining or geological conditions

 

•     underground floods

 

•     ground movement or cave-ins

 

•     tailings pipeline or dam failures

 

•     technological failure of mining methods

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

 

56     CAMECO CORPORATION

Uranium – production overview

Production in our uranium segment this quarter was 1 million pounds higher compared to the fourth quarter of 2012. Production for the year was 1.7 million pounds higher than in 2012. We set new annual and quarterly production records with these results. See Uranium – operating properties starting on page 58 for more information.

URANIUM PRODUCTION

 

CAMECO’S SHARE    THREE MONTHS ENDED
DECEMBER 31		      YEAR ENDED
DECEMBER 31		               

(MILLION LBS)

    2013      2012      2013      2012      2013 PLAN     2014 PLAN  

McArthur River/Key Lake

      4.0         3.5         14.1         13.6         13.6 1      13.1   

Rabbit Lake

      2.1         1.7         4.1         3.8         4.2        4.1   

Smith Ranch-Highland

      0.5         0.3         1.7         1.1         1.6 1      2.0   

Crow Butte

      0.2         0.2         0.7         0.8         0.7 1      0.6   

Inkai

      0.7         0.8         3.0         2.6         2.9        3.0   

Cigar Lake

      —           —           —           —           —   1      1.0 – 1.5   
  

 

 

     

 

 

     

 

 

     

 

 

     

 

 

    

 

 

  

Total

      7.5         6.5         23.6         21.9         23.2        23.8 – 24.3   
  

 

 

     

 

 

     

 

 

     

 

 

     

 

 

    

 

 

  

 

1  We updated our initial 2013 plan for McArthur River/Key Lake (to 13.6 million pounds from 13.2 million pounds), US ISR (to 2.3 million pounds from 2.6 million pounds) and Cigar Lake (to nil from 0.3 million pounds) in our Q3 MD&A.

Outlook

Our strategy remains focused on taking advantage of the long-term growth we see coming in our industry, while maintaining the ability to respond to market conditions as they evolve. As a result of the longer-than-anticipated uncertainty that continues to persist in today’s market, it is no longer appropriate to pursue significant production growth to a fixed target. Although we still have an extensive portfolio of assets from which we can increase our production capacity, we have eliminated our 2018 supply target of 36 million pounds in order to allow us to respond to market signals, and as a result, it is no longer appropriate to provide a long-term production forecast.

We plan to:

 

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

 

•   ensure continued reliable, low-cost production at Inkai

 

•   successfully bring on and ramp up production at Cigar Lake

 

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    57

Uranium operating properties

 

LOGO        McArthur River / Key Lake
  McArthur River is the world’s largest, high-grade uranium mine, and Key Lake is the largest uranium mill in the world.
  Ore grades at the McArthur River mine are 100 times the world average, which means it can produce more than 18 million pounds per year by mining only 150 to 200 tonnes of ore per day. We are the operator.
  McArthur River is one of our three material uranium properties.

 

Location    Saskatchewan, Canada
Ownership   

69.805% – McArthur River

83.33% – Key Lake

End product    Uranium concentrates
ISO certification    ISO 14001 certified
Mine type    Underground
Estimated reserves (our share)    251.6 million pounds (proven and probable), average grade U3O8: 15.76%
Estimated resources (our share)   

9.5 million pounds (measured and indicated), average grade U3O8: 4.81%

39.9 million pounds (inferred), average grade U3O8: 7.38%

Mining methods   

Primary: raiseboring;

Secondary: blasthole stoping, boxhole boring

Licenced capacity    Mine and mill: 18.7 million pounds per year (can be exceeded – see Flexibility provisions)

Total production: 2000 to 2013

(100% basis)         1983 to 2002

   

250.6 million pounds (McArthur River/Key Lake)

209.8 million pounds (Key Lake)

2013 production (our share)    14.1 million pounds (20.1 million pounds on 100% basis)
2014 forecast production (our share)    13.1 million pounds (18.7 million pounds on 100% basis)

Estimated decommissioning cost

(100% basis)

   

$48 million – McArthur River

$218 million – Key Lake (estimate currently under review)

BACKGROUND

Mining methods and techniques

We use a number of innovative methods to mine the McArthur River deposit:

Ground freezing

The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. We use ground freezing to form an impermeable wall around the area being mined. This prevents water from entering the mine, and helps stabilize weak rock formations. To date, we have installed five freezewalls and are currently preparing a sixth.

Raisebore mining

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

 

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

 

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

 

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

 

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

 

•   starting the process again with the next raisebore chamber

 

58     CAMECO CORPORATION

We have used the raisebore mining method to successfully extract about 250 million pounds (100% basis) since we began mining in 1999. Raisebore mining is scheduled to remain the primary extraction method over the life of mine.

 

LOGO

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

Zone 2 has been actively mined since production began. It is divided into four panels (panels 1, 2, 3 and 5) based on the configuration of the freeze wall around the ore. As the freeze wall is expanded, the inner connecting freeze walls are decommissioned in order to recover the uranium that was inaccessible around the active freeze pipes. Panel 5 represents the upper portion of zone 2, overlying part of the other panels. Mining is nearing completion in panels 1, 2 and 3, and the majority of the remaining zone 2 proven mineral reserves are in panel 5.

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

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

Boxhole boring

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    59

Blasthole stoping

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

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

Initial processing

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

 

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

 

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

 

•   it is blended and thickened, removing excess water

 

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

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

2013 UPDATE

Production

Total production from McArthur River/Key Lake was 20.1 million pounds, which is the highest annual output from a uranium facility anywhere in the world. Our share of production in 2013 was 14.1 million pounds U3O8, 4% higher than our forecast for the year, and 4% higher than annual production in 2012.

At McArthur River and Key Lake we realized benefits under the production flexibility provision in our operating licences (see Flexibility provisions below). Ongoing efforts to improve the efficiency and reliability of the Key Lake mill resulted in record mill performance.

Licensing and production capacity

On October 29, 2013, the CNSC granted a renewal of our McArthur River and Key Lake operating licences. The licence term is from November 1, 2013 to October 31, 2023.

Flexibility provisions

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

 

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

 

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

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

McArthur River production expansion

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

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

 

60     CAMECO CORPORATION

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

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

 

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

 

•   expand the freeze plant and electrical distribution systems

 

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

 

•   improve our dewatering system and expand our water treatment capacity

New mining areas

We completed installation of the freezewall and brine lines in the upper mining area of zone 4 north. We began freezing the ground in the third quarter of 2013, with plans to start mining the zone in late 2014.

In addition to the underground work, we continued to upgrade our electrical infrastructure on surface to address the future need for increased ventilation and freeze capacity associated with mining new zones and increasing mine production.

Key Lake extension project and mill revitalization

The Key Lake mill began operating in 1983 and is currently licensed to produce 18.7 million pounds (100% basis) per year. Mill production at Key Lake is expected to closely follow McArthur River production, subject to receipt of regulatory approval. As part of our Key Lake extension environmental assessment (EA), we are seeking approval to increase Key Lake’s nominal annual production rate to 25 million pounds and to increase our tailings capacity; in 2014, we expect the federal and provincial EA to conclude and expect a decision to be made on these increases.

The mill revitalization plan includes upgrading circuits with new technology to simplify operations and improve environmental performance. Major components of a new calciner circuit were installed in 2013 and commissioning is expected to be completed in 2014. As part of the revitalization plan, we also replaced the existing electrical substation in order to meet future electrical demands.

Tailings capacity

This year we:

 

•   submitted the final environmental impact statement for review by the regulators, and plan to pursue the required regulatory approvals in 2014

 

•   completed flattening of the Deilmann tailings management facility pitwalls

Exploration

In 2013, our surface exploration programs continued to test zones of mineralization north of the current mining areas.

PLANNING FOR THE FUTURE

Production

We plan to produce 18.7 million pounds per year (13.1 million pounds our share) until we receive the required regulatory approvals and complete the work necessary to increase production at both McArthur River and Key Lake.

New mining zones

Zone 4 north is the next area to be mined. Freezing has begun and we forecast initial production to start in 2014.

We expect to use raisebore mining in this area, applying the ground freezing experience we gained in zone 2, panel 5. This should significantly improve production efficiencies compared to boxhole boring.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    61

Mill revitalization

In 2014, we expect to:

 

•   complete installation and commissioning of the new calciner

 

•   upgrade the electrical services necessary to add standby electrical generating capacity for the new electrically heated calciner

Key Lake extension project

In 2014, we expect to complete the regulatory process required to increase production to 25 million pounds per year at Key Lake. We will also seek approval to deposit tailings in the Deilmann tailings management facility to a higher level, providing enough tailings capacity to potentially mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

See Key Lake tailings capacity risk below for additional information.

Exploration

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

MANAGING OUR RISKS

Production at McArthur River/Key Lake poses many challenges: control of groundwater, weak rock formations, radiation protection, water inflow, mine area transitioning, regulatory approvals and tailings capacity. Operational experience gained since the start of production has resulted in a significant reduction in risk.

Labour relations

The current collective agreement with unionized employees at the McArthur River and Key Lake operations expired on December 31, 2013 and bargaining for a new agreement is currently underway. There is risk to production in 2014 if we are unable to reach an agreement and employees go on strike.

Transition to new mining areas

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

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

Key Lake tailings capacity risk

Tailings from processing McArthur River ore are deposited in the Deilmann tailings management facility. At current production rates, the facility will reach licensed capacity by 2018. A significant delay in obtaining or a failure to receive, the necessary regulatory approval for the expansion of the facility could interrupt or prevent the operation of McArthur River/ Key Lake as planned.

In the past, sloughing of material from the pitwalls has resulted in loss of capacity. Technical studies show that stabilizing and reducing water levels in the pit enhances the stability of the pitwalls and reduces the risk of sloughing. In 2009, regulators approved our plan for the long-term stabilization of the Deilmann tailings management facility pitwalls. We implemented the plan and completed the project in 2013. We are proceeding with the environmental assessment to support an application for regulatory approval to deposit tailings to a higher level. This would provide enough tailings capacity to mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

Water inflow risk

The greatest risk is production interruption from water inflows. A 2003 water inflow resulted in a three-month suspension of production. We also had a small water inflow in 2008 that did not impact production.

 

 

62     CAMECO CORPORATION

The consequences of another water inflow at McArthur River would depend on its magnitude, location and timing, but could include a significant interruption or reduction in production, a material increase in costs or a loss of mineral reserves.

We take the following steps to reduce the risk of inflows, but there is no guarantee that these will be successful:

 

•   Ground freezing: Before mining, we drill freezeholes and freeze the ground to form an impermeable freezewall around the area being mined. Ground freezing reduces but does not eliminate the risk of water inflows.

 

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

 

•   Pumping capacity and treatment limits: Our standard for this project is to secure pumping capacity of at least one and a half times the estimated maximum sustained inflow. We review our dewatering system and requirements at least once a year and before beginning work on any new zone.

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

We also manage the risks listed on pages 55 to 56.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    63

Uranium – operating properties

 

LOGO   

Rabbit Lake

 

The Rabbit Lake operation, which opened in 1975, is the longest operating uranium production facility in North America, and the second largest uranium mill in the world.

 

Location

    Saskatchewan, Canada

Ownership

    100%

End product

    Uranium concentrates

ISO certification

    ISO 14001 certified

Mine type

    Underground

Estimated reserves

    20.3 million pounds (proven and probable), average grade U3O8: 0.56%

Estimated resources

   

20.2 million pounds (indicated), average grade U3O8: 0.80%

9.0 million pounds (inferred), average grade U3O8: 0.58%

Mining methods

    Vertical blasthole stoping

Licenced capacity

    Mill: maximum 16.9 million pounds per year; currently 11 million

Total production: 1975 to 2013

    190.1 million pounds

2013 production

    4.1 million pounds

2014 forecast production

    4.1 million pounds

Estimated decommissioning cost

    $203 million

2013 UPDATE

Production

Production this year was 8% higher than 2012 production as a result of improved efficiency of the mill operating schedule.

Development and production continued at Eagle Point mine. At the mill, we continued to improve performance by replacing key pieces of mill infrastructure and improving the efficiency of the mill operation schedule. The mill ran continuously for eight months and maintenance work was completed during an extended shutdown period of four months.

Exploration

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

We extended our underground drilling reserve replacement program into 2013, testing beneath existing zones as well as to the east and northeast of the current mine workings (including Powell Zone). See Mineral reserves and resources on page 84 for more information.

Licensing

On October 29, 2013, the CNSC granted a renewal of our Rabbit Lake operating licences. The licence term is from November 1, 2013 to October 31, 2023.

 

64     CAMECO CORPORATION

PLANNING FOR THE FUTURE

Production

We expect to produce 4.1 million pounds in 2014.

Tailings capacity

We expect to have sufficient tailings capacity to support milling of Eagle Point ore until about 2018 (based upon expected ore tonnage and milling rates).

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

Exploration

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

Reclamation

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

MANAGING OUR RISKS

We manage the risks listed on pages 55 to 56.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    65

Uranium – operating properties

 

LOGO   

Smith Ranch-Highland

 

We operate Smith Ranch and Highland as a combined operation. Each has its own processing facility, but the Smith Ranch central plant currently processes all the uranium, including uranium from satellite facilities. The Highland plant is currently idle. Together, they form the largest uranium production facility in the United States.

 

Location

    Wyoming, US

Ownership

    100%

End product

    Uranium concentrates

ISO certification

    ISO 14001 certified

Estimated reserves

   

Smith Ranch-Highland:

5.2 million pounds (proven and probable), average grade U3O8: 0.09%

North Butte-Brown Ranch:

3.8 million pounds (proven and probable), average grade U3O8: 0.08%

Estimated resources

   

Smith Ranch-Highland:

21.8 million pounds (measured and indicated), average grade U3O8: 0.06%

7.9 million pounds (inferred), average grade U3O8: 0.05%

North Butte-Brown Ranch

10.8 million pounds (measured and indicated), average grade U3O8: 0.07%

0.8 million pounds (inferred), average grade U3O8: 0.06%

Mining methods

    In situ recovery (ISR)

Licenced capacity

    Wellfields: 3 million pounds per year Processing plants: 5.5 million pounds per year including Highland mill

Total production: 2002 to 2013

    17.6 million pounds

2013 production

    1.7 million pounds

2014 forecast production

    2.0 million pounds

Estimated decommissioning cost

    $202 million (US)

2013 UPDATE

Production

Production this year was 6% higher than our forecast and significantly higher than 2012 production, with new mine units contributing to production at Smith Ranch-Highland in 2013, as well as the startup of the North Butte satellite.

Our North Butte satellite began production during the second quarter and produced 300,000 pounds in 2013. We expect to ramp up to a target annual production rate of more than 700,000 pounds per year by 2015 from the North Butte satellite operation. We continue to seek regulatory approvals to proceed with the rest of our expansion plans.

Licensing

The regulators continue to review our licence renewal application. We are allowed to continue with all previously approved activities during the licence renewal process.

PLANNING FOR THE FUTURE

Production

In 2014, we expect to produce 2.0 million pounds.

MANAGING OUR RISKS

We manage the risks listed on pages 55 to 56.

 

66     CAMECO CORPORATION

Uranium – operating properties

 

LOGO   

Crow Butte

 

Crow Butte was discovered in 1980 and began production in 1991. It is the first uranium mine in Nebraska, and is a significant contributor to the economy of northwest Nebraska.

 

Location

    Nebraska, US

Ownership

    100%

End product

    Uranium concentrates

ISO certification

    ISO 14001 certified

Estimated reserves

    2.3 million pounds (proven), average grade U3O8: 0.11%

Estimated resources

   

14.6 million pounds (indicated), average grade U3O8: 0.27%

2.9 million pounds (inferred), average grade U3O8: 0.12%

Mining methods

    In situ recovery (ISR)

Licenced capacity

(processing plants and wellfields)

    2.0 million pounds per year

Total production: 2002 to 2013

    9.1 million pounds

2013 production

    0.7 million pounds

2014 forecast production

    0.6 million pounds

Estimated decommissioning cost

    $44 million (US)

2013 UPDATE

Production

Production this year was as forecast, but slighter lower than 2012 production.

Licensing

The regulators continued to review our applications to expand and re-license Crow Butte. We are allowed to continue with all previously approved activities during the licence renewal process.

PLANNING FOR THE FUTURE

Production

In 2014, we expect to produce 0.6 million pounds.

Managing our risks

We manage the risks listed on pages 55 to 56.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    67

Uranium – operating properties

 

LOGO   

Inkai

 

Inkai is a very significant uranium deposit, located in Kazakhstan. There are two production areas (blocks 1 and 2) and an exploration area (block 3). The operator is joint venture Inkai limited liability partnership, which we jointly own (60%) with Kazatomprom (40%).

 

Inkai is one of our three material uranium properties.

 

Location

    South Kazakhstan

Ownership

    60%

End product

    Uranium concentrates

Certifications

   

BSI OHSAS 18001

ISO 14001 certified

Estimated reserves (our share)

    50.4 million pounds (proven and probable), average grade U3O8: 0.07%

Estimated resources (our share)

   

28.3 million pounds (indicated), average grade U3O8: 0.08%

146.3 million pounds (inferred), average grade U3O8: 0.05%

Mining methods

    In situ recovery (ISR)

Licenced capacity (wellfields)

    5.2 million pounds per year, (our share 3.0 million pounds per year)

Total production: 2008 to 2013 (our share)

    12.0 million pounds

2013 production (our share)

    3.0 million pounds (5.2 million pound on 100% basis)

2014 forecast production (our share)

    3.0 million pounds (5.2 million pounds on 100% basis)

Estimated decommissioning cost

(100% basis )

    $14 million (US)

2013 UPDATE

Production

Production this year was slightly higher than our forecast for the year and 15% higher than production in 2012. Inkai added new wellfields to the production mix, which increased the head grade and resulted in higher 2013 production.

Licensing

In December 2013, Inkai received government approval of an amendment to the resource use contract to increase production from blocks 1 and 2 to 5.2 million pounds (100% basis). Our share of Inkai’s annual production is 3.0 million pounds with the processing plant at full capacity.

Project funding

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

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

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

 

68     CAMECO CORPORATION

Uranium conversion project and doubling production update

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

 

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

 

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

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

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

Block 3 exploration

In 2013, Inkai:

 

•   completed exploration drilling

 

•   continued construction of the test leach facility and test wellfields

 

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

PLANNING FOR THE FUTURE

Production

We expect our share of production to be 3.0 million pounds in 2014 from blocks 1 and 2. We expect to maintain production at this level until the potential expansion under the 2012 MOA proceeds.

Block 3 exploration

In 2014, Inkai expects to:

 

•   complete construction of the test leach facility and test wellfields

 

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

 

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

MANAGING OUR RISKS

Supply of sulphuric acid

There were no interruptions to sulphuric acid supply during 2013. Given the importance of sulphuric acid to Inkai’s mining operations and shortages in previous years, we continue to closely monitor its availability. Our production may be less than forecast if there is a shortage.

Political risk

Kazakhstan declared itself independent in 1991 after the dissolution of the Soviet Union. Our Inkai investment, and our plans to increase production, are subject to the risks associated with doing business in developing countries, which have significant potential for social, economic, political, legal and fiscal instability. Kazakh laws and regulations are complex and still developing and their application can be difficult to predict. To maintain and increase Inkai production, we need ongoing support, agreement and co-operation from our partner and the government.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    69

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

In general, Inkai’s licences are governed by the version of the subsoil law that was in effect when the licences were issued in April 1999, and new legislation applies to Inkai only if it does not worsen Inkai’s position. Changes to legislation related to national security, among other criteria, however, are exempt from the stabilization clause in the resource use contract. The Kazakh government interprets the national security exemption broadly.

With the 2010 subsoil law, the government continues to weaken its stabilization guarantee. The government is broadly applying the national security exception to encompass security over strategic national resources.

The resource use contract contains significantly broader stabilization provisions than the 2010 subsoil law, and these contract provisions currently apply to us.

To date, the 2010 subsoil law has not had a significant impact on Inkai. We continue to assess the impact. See our annual information form for an overview of this change in law.

We also manage the risks listed on pages 55 to 56.

 

70     CAMECO CORPORATION

Uranium – development project

 

LOGO   

Cigar Lake

 

Cigar Lake is the world’s second largest high-grade uranium deposit, with grades that are 100 times the world average. We are a 50% owner and the mine operator.

 

Cigar Lake, which is being developed and scheduled to begin production this year, is one of our three material uranium properties.

 

Location

    Saskatchewan, Canada

Ownership

    50.025%

End product

    Uranium concentrates

Mine type

    Underground

Estimated reserves (our share)

    108.4 million pounds (proven and probable), average grade U3O8: 18.30%

Estimated resources (our share)

   

1.1 million pounds (measured and indicated), average grade U3O8: 2.27%

49.5 million pounds (inferred), average grade U3O8: 12.01%

Mining methods

    Jet boring

Target production date

   

First mine production in the first quarter of 2014

Begin processing ore at the McClean Lake mill by the end of the second quarter of 2014

Target annual production (our share)

    9 million pounds at full production (18.0 million pounds on 100% basis)

2014 forecast production (our share)

    1.0 – 1.5 million pounds (2.0 to 3.0 million pounds on 100% basis)

Estimated decommissioning cost

(100% basis )

    $49 million

 

LOGO

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    71

BACKGROUND

Development

We began developing the Cigar Lake underground mine in 2005, but development was delayed due to water inflows (two in 2006 and one in 2008). The first inflow flooded shaft 2 while it was under construction. The second inflow flooded the underground development and we began remediation late in 2006. In 2008, another inflow interrupted the dewatering of the underground development. We sealed the inflows and completed dewatering of shafts 1 and 2. In 2011, we completed remediation of the underground.

Mining method

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

Bulk freezing

The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. We will freeze the ore zone and surrounding ground in the area to be mined to prevent water from entering the mine and to help stabilize weak rock formations.

Our plan is to use a hybrid freezing approach. We will use surface freezing to support the rampup period and underground freezing for the longer term development of the mine. Through 2013, we continued to drill freezeholes from surface, expand the surface freezing infrastructure and put the new freezeholes in operation. To manage our risks and meet our production schedule, the area being mined must meet specific ground freezing requirements before we begin jet boring.

Jet boring

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

 

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

 

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

 

•   using a clamshell, transporting the ore from the sump storage to a grinding and processing circuit, eventually loading a tanker truck with ore slurry for transport to the mill

 

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

 

•   starting the process again with the next cavity

Jet boring system process

 

LOGO

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

 

72     CAMECO CORPORATION

In September 2013, we announced that we had identified additional underground work that would delay jet boring in ore. After the work was completed, we jetted the first ore cavity in December 2013, and expect to begin ore production from the mine during the first quarter of 2014.

Milling

All of Cigar Lake’s ore slurry will be processed at the McClean Lake mill, operated by AREVA. The McClean Lake mill requires modification and expansion to process and package all of Cigar Lake’s current mineral reserves. The Cigar Lake joint venture has agreed to pay for the capital costs for such modification and expansion.

In September 2013, AREVA advised us that it had determined that further mill modifications were required before they could begin processing Cigar Lake ore. The McClean Lake mill is expected to begin processing Cigar Lake ore by the end of the second quarter of 2014.

2013 UPDATE

During the year, we:

 

•   completed construction and began commissioning of all infrastructure required to begin ore production

 

•   successfully tested the jet boring system in waste and began commissioning in ore

 

•   continued freezing the ground from surface to ensure frozen ore is available for future production years

Costs

As of December 31, 2013, we had:

 

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

 

•   expensed about $86 million in remediation expenses

 

•   expensed about $100 million in standby costs

 

•   expensed about $102 million to begin commissioning

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

Licensing

The CNSC granted a uranium mining licence authorizing construction and operation of the Cigar Lake project. The licence term is from July 1, 2013 to June 30, 2021.

PLANNING FOR THE FUTURE

Production

In 2014, we expect:

 

•   to bring the mine into production in the first quarter of 2014

 

•   processing of the ore to begin at AREVA’s McClean Lake mill by the end of the second quarter of 2014

Rampup schedule

We expect Cigar Lake to produce between 2 million and 3 million packaged pounds from the mill (100% basis) in 2014. Based upon our commissioning and rampup experience, we will adjust our plans as necessary to allow us to reach our full production rate of 18 million pounds (100% basis) by 2018.

Given the scale of this project and the challenging nature of the geology and mining method, we have made significant progress. We will continue to develop this asset in a safe and deliberate manner to ensure we realize the economic benefits of this project.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    73

Caution regarding forward-looking information

Our expectations and plans regarding Cigar Lake, including our expected share of 2014 production, achievement of the full production rate of 18 million pounds by 2018, and capital costs, are forward-looking information. They are based on the assumptions and subject to the material risks discussed on pages 2 and 3, and specifically on these assumptions and risks:

 

Assumptions

 

•   our Cigar Lake development, mining and production plans succeed

 

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

 

•   there are no labour disputes or shortages

 

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

 

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

 

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

 

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

 

•   mill modifications and commissioning of the McClean Lake mill are completed as planned and the mill is able to process Cigar Lake ore as expected, AREVA will be able to solve technical challenges as they arise in a timely manner, and sufficient tailings facility capacity is available
•   our mineral reserves estimate and the assumptions it is based on are reliable

Material risks

 

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

 

•   ground movements or cave-ins

 

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

 

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

 

•   sufficient tailings facility capacity is not available

 

•   our mineral reserves estimate is not reliable

 

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

 

MANAGING OUR RISKS

Cigar Lake is a challenging deposit to develop and mine. These challenges include control of groundwater, weak rock formations, radiation protection, water inflow, mining method uncertainty, regulatory approvals, tailings capacity, surface and underground fires and other mining-related challenges. To reduce this risk, we are applying our operational experience and the lessons we have learned about water inflows at McArthur River and Cigar Lake.

Mill modifications

There is a risk to Cigar Lake’s ramp up schedule if the McClean Lake mill does not begin processing ore from the Cigar Lake mine by the end of the second quarter, 2014. There is also a risk to our plan to achieve the full production rate of 18 million pounds per year by 2018 if AREVA is unable to complete and commission the required mill upgrades on schedule. We are working closely with AREVA to understand and help mitigate the risks to ensure that mine and mill production schedules are aligned.

Ground freezing

To manage our risks and meet our production schedule, the areas being mined must meet specific ground freezing requirements before we begin jet boring. We have identified greater variation of the freeze rates of different geological formations encountered in the mine, based on new information obtained through surface freeze drilling. As a mitigation measure, we have increased the site freeze capacity to facilitate the extraction of ore cavities as planned.

 

74     CAMECO CORPORATION

Jet boring mining method and units

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

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

Water inflow risk

A significant risk to development and production is from water inflows. The 2006 and 2008 water inflows were significant setbacks.

The consequences of another water inflow at Cigar Lake would depend on its magnitude, location and timing, but could include a significant delay in Cigar Lake’s development or production, a material increase in costs or a loss of mineral reserves.

We take the following steps to reduce the risk of inflows, but there is no guarantee that these will be successful:

 

•   Bulk freezing: Two of the primary challenges in mining the deposit are control of groundwater and ground support. Bulk freezing reduces but does not eliminate the risk of water inflows.

 

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

 

•   Pumping capacity and treatment limits: We have pumping capacity to meet our standard for this project of at least one and a half times the estimated maximum inflow.

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

We also manage the risks listed on pages 55 to 56.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    75

Uranium – projects under evaluation

We continue to advance our projects under evaluation toward development decisions at a pace aligned with market opportunities in order to respond should the market signal a need for more uranium.

The process includes several defined decision points in the assessment and development stages. At each point, we re-evaluate the project based on current economic, competitive, social, legal, political and environmental considerations. If it continues to meet our criteria, we proceed to the next stage. This process allows us to build a pipeline of projects ready for a production decision and minimize expenditures on projects whose feasibility has not yet been determined.

 

LOGO

Millennium

 

Location

    Saskatchewan, Canada

Ownership

    69.9%

End product

    Uranium concentrates

Mine type

    Underground

Estimated resources (our share)

   

53.0 million pounds (indicated), average grade U3O8: 2.39%

20.2 million pounds (inferred), average grade U3O8: 3.19%

BACKGROUND

The Millennium deposit was discovered in 2000, and was delineated through geophysical survey and drilling work between 2000 and 2013. In 2012, we paid $150 million to acquire AREVA’s 27.94% interest in the project, bringing our interest in the project to 69.9%. We are the operator.

2013 UPDATE

This year we:

 

•   submitted the final environmental impact statement to regulators

 

•   completed a drill program that successfully increased the indicated resources of the deposit

In 2014, we expect a decision from the CNSC on a construction and operating licence for Millennium. A positive outcome and receipt of a licence would allow us to quickly advance to a development decision on the project, once the market signals that new production is needed.

Yeelirrie

 

LOCATION

    Western Australia

Ownership

    100%

End product

    Uranium concentrates

Mine type

    Open pit

Estimated resources

    127.3 million pounds (measured and indicated), average grade U3O8: 0.16%

 

76     CAMECO CORPORATION

BACKGROUND

In 2012, we paid $430 million (US) (as well as $22 million (US) in stamp duty) to acquire the Yeelirrie uranium deposit. The deposit was discovered in 1972 and is a near-surface calcrete-style deposit that is amenable to open pit mining techniques. It is one of Australia’s largest undeveloped uranium deposits.

2013 UPDATE

This year, we are reporting a new mineral resources estimate in accordance with National Instrument 43-101 – Standards of Disclosure for Mineral Projects (NI 43-101) based on a full document review, data validation, geological re-interpretation and modeling. We have provided the updated estimate in Mineral reserves and resources, starting on page 84.

Kintyre

 

LOCATION

    Western Australia

Ownership

    70%

End product

    Uranium concentrates

Mine type

    Open pit

Estimated resources (our share)

   

38.7 million pounds (indicated), average grade U3O8: 0.58%

6.7 million pounds (inferred), average grade U3O8: 0.46%

BACKGROUND

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

2013 UPDATE

This year we:

 

•   completed the value engineering study

 

•   completed registration of the Kintyre Mining Development Indigenous Land Use Agreement with the relevant government authority

 

•   submitted an Environmental Review and Management Program

 

•   carried out further exploration to test for potential satellite deposits at Kintyre and at other regional exploration projects close to Kintyre

MANAGING THE RISKS

For all of our projects under evaluation, we manage the risks listed on pages 55 to 56.

Additional risks for Millennium include:

 

•   The English River First Nation (ERFN) selected surface lands covering the Millennium deposit in a claim for Treaty Land Entitlement (TLE). The TLE process does not affect our mineral rights, but it could have an impact on the surface rights and benefits we ultimately negotiate as part of the development of this deposit. Under the collaboration agreement that we signed with ERFN in 2013, the TLE claim will be dropped.

 

•   Environment Canada has brought forward a national recovery plan for woodland caribou that has the potential to impact economic and social development in northern Saskatchewan. Additional research work is being conducted so that a determination can be made on the sustainability of the species within the region. The research could result in measures being taken to further limit habitat disturbance in order to improve the health of the woodland caribou population in northern Saskatchewan and it could have an impact on our ability to develop this deposit.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    77

Uranium – exploration and corporate development

Our exploration program is directed at replacing mineral reserves as they are depleted by our production, and ensuring our future growth. We have maintained an active program even during periods of weak uranium prices, which has helped us secure land with exploration and development prospects that are among the best in the world, mainly in Canada, Australia, Kazakhstan and the US. Globally, our land holdings total 2.0 million hectares (4.9 million acres). In northern Saskatchewan alone, we have direct interests in 584,000 hectares (1.4 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin. Many of our prospects are located close to our existing operations where we have established infrastructure and capacity to expand.

For properties that meet our investment criteria, we may partner with other companies through strategic alliances, equity holdings and traditional joint venture arrangements. Our leadership position and industry expertise in both exploration and corporate social responsibility make us a partner of choice.

 

LOGO

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

 

78     CAMECO CORPORATION

 

LOGO

2013 UPDATE

Brownfield exploration

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

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

Regional exploration

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

PLANNING FOR THE FUTURE

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

Brownfield exploration

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

Regional exploration

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

ACQUISITION PROGRAM

We have a dedicated team looking for acquisition opportunities within the nuclear fuel cycle that could further add to our supply, support our sales activities and complement and enhance our business in the nuclear industry. We will invest when an opportunity is available at the right time and the right price. We strive to pursue corporate development initiatives that will leave us and our shareholders in a fundamentally stronger position.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    79

Fuel services – refining, conversion and fuel manufacturing

We control about 25% of world UF6 conversion capacity and are a supplier of natural UO2. Our focus is on cost-competitiveness and operational efficiency.

Our fuel services segment is strategically important because it helps support the growth of the uranium segment. Offering a range of products and services to customers helps us broaden our business relationships and expand our uranium market share.

 

LOGO   

Blind River Refinery

 

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

 

Location

    Ontario, Canada

Ownership

    100%

End product

    UO3

ISO certification

    ISO 14001 certified

Licensed capacity

    24 million kgU as UO3 per year (subject to the completion of certain equipment upgrades)

Estimated decommissioning cost

    $39 million

2013 UPDATE

Production

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

MANAGING OUR RISKS

We manage the risks listed on pages 55 to 56.

 

80     CAMECO CORPORATION

LOGO   

Port Hope Conversion Services

 

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

 

Location

    Ontario, Canada

Ownership

    100%

End product

    UF6, UO2

ISO certification

    ISO 14001 certified

Licensed capacity

   

12.5 million kgU as UF6 per year

2.8 million kgU as UO2 per year

Estimated decommissioning cost

    $102 million

Cameco Fuel Manufacturing Inc. (CFM)

CFM produces fuel bundles and reactor components for CANDU reactors.

 

Location

    Ontario, Canada

Ownership

    100%

End product

    CANDU fuel bundles and components

ISO certification

    ISO 9001 certified, ISO 14001 certified

Licensed capacity

    1.2 million kgU as UO2 as finished bundles

Estimated decommissioning cost

    $20 million

Springfields Fuels Ltd. (SFL)

SFL is the newest conversion facility in the world. We contract almost all of its capacity through a toll-processing agreement to 2016.

 

Location

    Lancashire, UK

Toll-processing agreement

    Annual conversion of 5 million kgU as UO3 to UF6

Licensed capacity

    6.0 million kgU as UF6 per year

2013 UPDATE

Production

Fuel services produced 14.9 million kgU, slightly higher than our plan at the beginning of the year and 5% higher than 2012 when we reduced production in response to weak market conditions.

Labour relations

In July, unionized employees at our Port Hope conversion facility accepted new three-year collective agreements, which include a 6% wage increase over the term of the agreements.

Port Hope conversion facility cleanup and modernization (Vision in Motion, formerly Vision 2010)

In December 2012, we received a positive decision on the environmental assessment for the project from Canada’s Environment Minister. In 2013, we began the licensing process with the CNSC, which is required to advance the project. The process will continue in 2014.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    81

Springfields toll milling agreement

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

PLANNING FOR THE FUTURE

Production

We have decreased our production target for 2014 to between 13 million and 14 million kgU in response to weak market conditions.

MANAGING OUR RISKS

We also manage the risks listed on pages 55 to 56.

 

82     CAMECO CORPORATION

NUKEM GmbH

 

Offices   

Alzenau, Germany (Headquarters, NUKEM GmbH)

Connecticut, US (Subsidiary, NUKEM Inc.)

Ownership    100%
Activity    trading of uranium and uranium-related products
2013 sales    8.9 million lbs U3O8
2014 forecast sales    9 to 11 million lbs U3O8

BACKGROUND

In January 2013, we completed the acquisition of NUKEM, one of the world’s leading traders of uranium and uranium-related products. On closing, we paid €107 million ($140 million (US)) and assumed NUKEM’s net debt of about €84 million ($111 million (US)).

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

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

NUKEM’s business model

NUKEM’s purchase contracts are with longstanding supply partners and its sales contracts are with blue-chip utilities which have strong credit ratings.

MANAGING OUR RISKS

NUKEM manages the risks associated with trading and brokering nuclear fuels and services. It participates in the uranium spot market making purchases to place material in higher price contracts. There are risks associated with these spot market purchases including the risk of losses. NUKEM is also subject to counterparty risk of suppliers not meeting their delivery commitments and purchasers not paying for the product delivered. If a counterparty defaults on a payment or other obligation or becomes insolvent, this could significantly affect NUKEM’s contribution to our earnings, cash flows, financial condition or results of operations.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    83

Mineral reserves and resources

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

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

We estimate and disclose mineral reserves and resources in five categories, using the definitions adopted by the Canadian Institute of Mining, Metallurgy and Petroleum, and in accordance with Canadian National Instrument 43-101 – Standards of Disclosure for Mineral Projects (NI 43-101), developed by the Canadian Securities Administrators. You can find out more about these categories at www.cim.org.

About mineral resources

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

 

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

 

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

 

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

 

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

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

About mineral reserves

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

 

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

 

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

We use current geological models, an average uranium price of $63.75 (US) per pound U3O8, and current or projected operating costs and mine plans to estimate our mineral reserves, allowing for dilution and mining losses. We apply our standard data verification process for every estimate.

The price assumption is based on independent industry and analyst estimates of spot prices and the corresponding long-term prices and reflects our committed and uncommitted sales volumes. For committed sales volumes, the spot and term price assumptions were applied in accordance with the terms of the agreements. For uncommitted sales volumes the same price assumptions were applied using a spot-to-term price ratio of 60:40.

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

 

84     CAMECO CORPORATION

Changes this year

Our share of proven and probable mineral reserves went from 465 million pounds U3O8 at the end of 2012 to 443 million pounds at the end of 2013. The change in reserves was mainly the result of:

 

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

 

•   the upgrade of zone 1 at McArthur River from probable reserves to proven due to completion of detailed mining plans

 

•   the conversion of mineral reserves to resources at Gas Hills due to geological re-interpretation, re-estimation, and non demonstrated profitability

Measured and indicated mineral resources increased from 244 million pounds U3O8 at the end of 2012 to 391 million pounds at the end of 2013. Our share of inferred mineral resources is 289 million pounds U3O8.

The variance in resources was mainly the result of:

 

•   the addition of Yeelirrie mineral resources

 

•   the addition of indicated resources at Rabbit Lake from delineation drilling and conversion of inferred to indicated

 

•   the addition of indicated and inferred resources to Millennium from drilling

 

•   the conversion of mineral reserves to resources at Gas Hills

Qualified persons

The technical and scientific information discussed in this MD&A for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) was approved by the following individuals who are qualified persons for the purposes of NI 43-101:

 

McArthur River/Key Lake

 

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

 

•   David Bronkhorst, vice-president, mining and technology, Cameco

 

•   Greg Murdock, mine manager, Rabbit Lake, Cameco

 

•   Les Yesnik, general manager, Key Lake, Cameco

Cigar Lake

 

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

 

•   Eric Paulsen, chief metallurgist, technology group, Cameco

 

•   Scott Bishop, principal mine engineer, technology group, Cameco

Inkai

 

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

 

•   Ken Gullen, technical director, international, Cameco

 

•   Lawrence Reimann, manager, technical services, Cameco Resources
 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    85

Important information about mineral reserve and resource estimates

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

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

 

•   geological interpretation

 

•   extraction plans

 

•   commodity prices and currency exchange rates

 

•   recovery rates

 

•   operating and capital costs

There is no assurance that the indicated levels of uranium will be produced, and we may have to re-estimate our mineral reserves based on actual production experience. Changes in the price of uranium, production costs or recovery rates could make it unprofitable for us to operate or develop a particular site or sites for a period of time. See page 2 for information about forward-looking information.

Please see our mineral reserves and resources section of our annual information form for the specific assumptions, parameters and methods used for McArthur River, Inkai and Cigar Lake mineral reserve and resource estimates.

Important information for US investors

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

 

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

 

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

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

Other information concerning descriptions of mineralization, mineral reserves and resources may not be comparable to information made public by companies that comply with the SEC’s reporting and disclosure requirements for US domestic mining companies, including Industry Guide 7.

 

86     CAMECO CORPORATION

Mineral reserves

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

Proven and probable

(tonnes in thousands; pounds in millions)

 

                                                           

PROPERTY

   MINING
METHOD		     PROVEN     PROBABLE     TOTAL MINERAL RESERVES  
    TONNES     GRADE
% U3O8		     CONTENT
(LBS U3O8)		     TONNES     GRADE
% U3O8		     CONTENT
(LBS U3O8)		     TONNES     GRADE
% U3O8		     CONTENT
(LBS U3O8)		     CAMECO’S
SHARE OF
CONTENT
(LBS U3O8)		     METALLUR-GICAL
RECOVERY (%)		  

McArthur River

     UG        465.2        21.42        219.7        572.2        11.17        140.8        1,037.4        15.76        360.5        251.6        98.7   

Cigar Lake

     UG        233.6        22.31        114.9        303.5        15.22        101.8        537.1        18.30        216.7        108.4        98.5   

Rabbit Lake

     UG        43.0        0.29        0.3        1,599.1        0.57        20.0        1,642.1        0.56        20.3        20.3        97   

Key Lake

     OP        67.5        0.50        0.7              67.5        0.50        0.7        0.6        98.7   

Inkai

     ISR        1,947.1        0.08        3.6        57,742.6        0.07        84.0        59,689.7        0.07        87.6        50.4        85   

Smith Ranch-Highland

     ISR        1,100.8        0.10        2.5        1,498.3        0.08        2.7        2,599.1        0.09        5.2        5.2        80   

North Butte-Brown Ranch

     ISR        925.1        0.09        1.8        1,361.9        0.07        2.0        2,287.0        0.08        3.8        3.8        80   

Crow Butte

     ISR        928.6        0.11        2.3              928.6        0.11        2.3        2.3        85   
   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

Total

       5,710.8        —          345.7        63,077.6        —          351.5        68,788.5        —          697.2        442.7     
   

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

Notes

UG – underground

OP – open pit

ISR – in situ recovery

Estimates in the above table:

 

  •   use an average uranium price of $63.75 (US)/lb U3O8

 

  •   are based on an average exchange rate of $1.00 US=$1.05 Cdn

 

  •   Totals may not add up due to rounding.

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

METALLURGICAL RECOVERY

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    87

Mineral resources

As at December 31, 2013 (100% – only the last column shows our share)

Measured and indicated

(tonnes in thousands; pounds in millions)

 

PROPERTY

    MINING
METHOD		      MEASURED      INDICATED      TOTAL MEASURED AND INDICATED  
      TONNES      GRADE
% U3O8		      CONTENT
(LBS U3O8)		      TONNES      GRADE
% U3O8		      CONTENT
(LBS U3O8)		      TONNES      GRADE
% U3O8		      CONTENT
(LBS U3O8)		      CAMECO’S
SHARE
(LBS U3O8)		  

McArthur River

      UG         111.2         4.13         10.1         16.7         9.36         3.5         127.9         4.81         13.6         9.5   

Cigar Lake

      UG         18.9         1.68         0.7         25.5         2.71         1.5         44.4         2.27         2.2         1.1   

Rabbit Lake

      UG                  1,152.6         0.80         20.2         1,152.6         0.80         20.2         20.2   

Millennium

      UG                  1,442.6         2.39         75.9         1,442.6         2.39         75.9         53.0   

Phoenix

      UG                  152.4         15.60         52.3         152.4         15.60         52.3         15.7   

Tamarack

      UG                  183.8         4.42         17.9         183.8         4.42         17.9         10.3   

Dawn Lake

      OP, UG                  347.0         1.69         12.9         347.0         1.69         12.9         7.4   

Kintyre

      OP                  4,315.4         0.58         55.2         4,315.4         0.58         55.2         38.7   

Yeelirrie

      OP         24,013.5         0.17         92.4         12,626.5         0.13         34.9         36,640.0         0.16         127.3         127.3   

Inkai

      ISR                  29,346.4         0.08         49.2         29,346.4         0.08         49.2         28.3   

Smith Ranch-Highland

      ISR         1,783.1         0.10         4.0         14,618.1         0.06         17.8         16,401.2         0.06         21.8         21.8   

North Butte-Brown Ranch

      ISR                  7,245.7         0.07         10.8         7,245.7         0.07         10.8         10.8   

Gas Hills-Peach

      ISR         4,558.8         0.10         9.7         5,214.7         0.11         12.2         9,773.5         0.10         21.9         21.9   

Crow Butte

      ISR         1,133.1         0.24         6.0         1,354.9         0.29         8.6         2,488.0         0.27         14.6         14.6   

Ruby Ranch

      ISR                  2,215.3         0.08         4.1         2,215.3         0.08         4.1         4.1   

Ruth

      ISR                  1,080.5         0.09         2.1         1,080.5         0.09         2.1         2.1   

Shirley Basin

      ISR         89.2         0.16         0.3         1,638.2         0.11         4.1         1,727.4         0.12         4.4         4.4   
     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

  

Total

         31,707.8         —           123.2         82,976.4         —           383.3         114,684.2         —           506.5         391.2   
     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

     

 

 

  

 

88     CAMECO CORPORATION

Inferred

(tonnes in thousands; pounds in millions)

 

PROPERTY

    MINING
METHOD		      TONNES      GRADE
% U3O8		      CONTENT
(LBS U3O8)		      CAMECO’S SHARE
(LBS U3O8)		  

McArthur River

      UG         350.7         7.38         57.1         39.9   

Cigar Lake

      UG         373.4         12.01         98.9         49.5   

Rabbit Lake

      UG         708.5         0.58         9.0         9.0   

Millennium

      UG         412.4         3.19         29.0         20.2   

Phoenix

      UG         11.6         29.80         7.6         2.3   

Tamarack

      UG         45.6         1.02         1.0         0.6   

Kintyre

      OP         950.2         0.46         9.6         6.7   

Inkai

      ISR         254,217.9         0.05         254.4         146.3   

Smith Ranch-Highland

      ISR         6,989.4         0.05         7.9         7.9   

North Butte-Brown Ranch

      ISR         594.3         0.06         0.8         0.8   

Gas Hills-Peach

      ISR         585.3         0.07         0.9         0.9   

Crow Butte

      ISR         1,135.2         0.12         2.9         2.9   

Ruby Ranch

      ISR         56.2         0.14         0.2         0.2   

Ruth

      ISR         210.9         0.08         0.4         0.4   

Shirley Basin

      ISR         508.0         0.10         1.1         1.1   
     

 

 

     

 

 

     

 

 

     

 

 

  

Total

         267,149.6         —           480.8         288.6   
     

 

 

     

 

 

     

 

 

     

 

 

  

Notes

UG – underground

OP – open pit

ISR – in situ recovery

Mineral resources do not include amounts that have been identified as mineral reserves.

Mineral resources do not have demonstrated economic viability. Totals may not add up due to rounding.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    89

Additional information

Due to the nature of our business, we are required to make estimates that affect the amount of assets and liabilities, revenues and expenses, commitments and contingencies we report. We base our estimates on our experience, our best judgment, guidelines established by the Canadian Institute of Mining, Metallurgy and Petroleum and on assumptions we believe are reasonable.

We believe the following critical accounting estimates reflect the more significant judgments used in the preparation of our financial statements.

DECOMMISSIONING AND RECLAMATION

We are required to estimate the cost of decommissioning and reclamation for each operation, but we normally do not incur these costs until an asset is nearing the end of its useful life. Regulatory requirements and decommissioning methods could change during that time, making our actual costs different from our estimates. A significant change in these costs or in our mineral reserves could have a material impact on our net earnings and financial position.

PROPERTY, PLANT AND EQUIPMENT

We depreciate property, plant and equipment primarily using the unit of production method, where the carrying value is reduced as resources are depleted. A change in our mineral reserves would change our depreciation expenses, and such a change could have a material impact on amounts charged to earnings.

We assess the carrying values of property, plant and equipment and goodwill every year, or more often if necessary. If we determine that we cannot recover the carrying value of an asset or goodwill, we write off the unrecoverable amount against current earnings. We base our assessment of recoverability on assumptions and judgments we make about future prices, production costs, our requirements for sustaining capital and our ability to economically recover mineral reserves. A material change in any of these assumptions could have a significant impact on the potential impairment of these assets.

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

TAXES

When we are preparing our financial statements, we estimate taxes in each jurisdiction we operate in, taking into consideration different tax rates, non-deductible expenses, valuation of deferred tax assets, changes in tax laws and our expectations for future results.

We base our estimates of deferred income taxes on temporary differences between the assets and liabilities we report in our financial statements, and the assets and liabilities determined by the tax laws in the various countries we operate in. We record deferred income taxes in our financial statements based on our estimated future cash flows, which includes estimates of non-deductible expenses. If these estimates are not accurate, there could be a material impact on our net earnings and financial position.

PENSION, POST-RETIREMENT AND POST EMPLOYMENT BENEFITS

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

 

90     CAMECO CORPORATION

Controls and procedures

We have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2013, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.

Management, including our CEO and our CFO, supervised and participated in the evaluation, and concluded that our disclosure controls and procedures are effective to provide a reasonable level of assurance that the information we are required to disclose in reports we file or submit under securities laws is recorded, processed, summarized and reported accurately, and within the time periods specified. It should be noted that, while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect the disclosure controls and procedures or internal control over financial reporting to be capable of preventing all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Management, including our CEO and our CFO, is responsible for establishing and maintaining internal control over financial reporting and conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2013. We have not made any change to our internal control over financial reporting during the 2013 fiscal year that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Amended and restated Bylaws

Our board has approved amended and restated bylaws for the corporation, which are now in effect, to replace bylaws approved in October 2013. Our shareholders will be asked to approve these bylaws at our 2014 annual and special meeting of shareholders. The amended and restated bylaws reflect our current practices and recommended best practices, and include an advance notice bylaw. The amended and restated bylaws will be available on our website, SEDAR and EDGAR.

The advance notice bylaw provides a transparent, structured and fair process for nominating directors under which all shareholders, whether voting by proxy or attending a meeting to elect directors, are made aware of potential proxy contests in advance of the meeting. Among other things, the advance notice bylaw fixes a deadline of not less than 30 days and not more than 65 days before a meeting of shareholders by which nominations for directors must be submitted to the corporation. We believe our shareholders should be given sufficient information and time to make appropriate decisions on the election of board representatives.

New standards and interpretations not yet adopted

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

FINANCIAL INSTRUMENTS

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    91

FINANCIAL ASSETS AND FINANCIAL LIABILITIES

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

LEVIES

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

DISCLOSURE OF RECOVERABLE AMOUNTS

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

 

92     CAMECO CORPORATION