CCJ Cameco Corporation

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

 

FORM 6-K

 

 

Report of Foreign Private Issuer

Pursuant to Rule 13a-16 or 15d-16

Under the Securities Exchange Act of 1934

For the month of February, 2016

 

 

Cameco Corporation

(Commission file No. 1-14228)

 

 

2121-11th Street West

Saskatoon, Saskatchewan, Canada S7M 1J3

(Address of Principal Executive Offices)

 

 

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F.

Form 20-F  ¨            Form 40-F  x

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes  ¨            No   x

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):

 

 

 

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Exhibit Index

 

Exhibit No.		Description		Page No.
1.		Press Release dated February 5, 2016 announcing financial results for the period ended December 31, 2015
2.		2015 Cameco Corporation Consolidated Financial Statements
3.		Annual Management’s Discussion and Analysis of Cameco Corporation’s 2015 Consolidated Financial Statements

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

Date: February 8, 2016				Cameco Corporation
				By:		“Sean A. Quinn”
						Sean A. Quinn
						Senior Vice-President, Chief Legal Officer and Corporate Secretary

TSX: CCO NYSE: CCJ				website: cameco.com currency: Cdn (unless noted)

2121 – 11th Street West, Saskatoon, Saskatchewan, S7M 1J3 Canada

Tel: (306) 956-6200 Fax: (306) 956-6201

Cameco reports fourth quarter and 2015 financial results

 

•

delivered on annual guidance amid weak market conditions

 

•

solid uranium segment results, record annual revenue and average realized price owing to a weaker Canadian dollar

 

•

record annual uranium production on the back of strong results at Cigar Lake

 

•

write-down of $210 million in the fourth quarter related to our Rabbit Lake operation

Saskatoon, Saskatchewan, Canada, February 5, 2016 . . . . . . . . . . . . . . . . . .

Cameco (TSX: CCO; NYSE: CCJ) today reported its consolidated financial and operating results for the fourth quarter and year ended December 31, 2015 in accordance with International Financial Reporting Standards (IFRS).

“In 2015, the company continued to perform well, in the context of the global challenges our industry faces,” said president and CEO, Tim Gitzel. “But despite the challenges, we continued to concentrate on the aspects of our business that are within our control, which has led us to once again deliver on, and in some cases exceed, our annual guidance.

“We are still waiting on a market recovery that was expected to come sooner, but we’ve learned to put those expectations aside and prepare for whatever comes our way. Looking ahead, our strategy is to continue focusing our capital on tier-one assets, because it’s those world-class, low-cost mines that will position us to quickly respond when the market calls for more production. And we believe that the question is not ‘if’ the market will make that call, but ‘when’, as we continue to see a bright long-term outlook for the nuclear industry.”

 

						THREE MONTHS ENDED DECEMBER 31												YEAR ENDED DECEMBER 31
HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED)						2015				2014				CHANGE				2015				2014				CHANGE
Revenue							975				889				10	%			2,754				2,398				15	%
Gross profit							282				251				12	%			697				638				9	%
Net earnings (loss) attributable to equity holders							(10	)			73				(114	)%			65				185				(65	)%
$ per common share (diluted)							(0.03	)			0.18				(114	)%			0.16				0.47				(65	)%
Adjusted net earnings (non-IFRS, see page 8)							151				205				(26	)%			344				412				(17	)%
$ per common share (adjusted and diluted)							0.38				0.52				(27	)%			0.87				1.04				(16	)%
Cash provided by operations (after working capital changes)							503				236				113	%			450				480				(6	)%
Average realized prices		Uranium		($US/lb)			46.36				50.57				(8	)%			45.19				47.53				(5	)%
				($Cdn/lb)			61.24				56.78				8	%			57.58				52.37				10	%
		Fuel Services		($Cdn/kgU)			21.88				16.92				29	%			23.37				19.70				19	%
		NUKEM		($Cdn/lb)			52.22				52.12				—				48.82				44.90				9	%

The 2015 annual financial statements have been audited; however, the 2014 and 2015 fourth quarter financial information presented is unaudited. You can find a copy of our 2015 annual management’s discussion and analysis (MD&A), and our 2015 audited financial statements, on our website at cameco.com.

 

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FULL YEAR

Our net earnings attributable to equity holders (net earnings) in 2015 were $65 million ($0.16 per share diluted) compared to $185 million ($0.47 per share diluted) in 2014, mainly due to:

 

•

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

 

•

lower tax recoveries, primarily due to the write-off of our deferred tax asset in the US

partially offset by:

 

•

lower impairment charges ($215 million in 2015; $327 million in 2014)

 

•

higher earnings in our uranium and fuel services segments due to higher average realized prices

 

•

higher earnings in our NUKEM segment as a result of higher volumes and average realized price

 

•

reduction of the provision related to our Canada Revenue Agency (CRA) litigation

In addition, in 2014 there were a number of one-time items that contributed to the higher net earnings in 2014 compared to 2015, including:

 

•

the sale of our interest in Bruce Power Limited Partnership (BPLP) resulting in a $127 million gain in 2014

 

•

a favourable settlement of $66 million in 2014 with respect to a dispute regarding a long-term supply contract with a utility customer

partially offset by:

 

•

payment of an early agreement termination fee of $18 million as a result of the cancellation of our toll conversion agreement with Springfields Fuels Limited (SFL), and $12 million for settlement costs with respect to early redemption of our Series C debentures in 2014

 

•

the write-off of $41 million of assets under construction in 2014 as a result of changes made to the scope of a number of projects

On an adjusted basis, our earnings were $344 million ($0.87 per share diluted) (non-IFRS measure, see page 8) in 2015 compared to $412 million ($1.04 per share diluted) in 2014.

The 17% decrease from 2014 to 2015 resulted from:

 

•

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

 

•

lower tax recoveries, primarily due to the write-off of our deferred tax asset in the US

partially offset by:

 

•

higher earnings in our uranium and fuel services segments mainly due to a higher average realized price

 

•

higher earnings from our NUKEM segment mainly due to higher sales volumes and a higher average realized price

 

•

a reduction of the provision related to our CRA litigation

In addition, in 2014 there was a favourable settlement of $66 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher adjusted net earnings in 2014 compared to 2015. The impact of the settlement was partially offset by an early termination fee of $18 million incurred as a result of the cancellation of our toll conversion agreement with SFL and settlement costs of $12 million with respect to the early redemption of our Series C debentures in 2014.

FOURTH QUARTER

In the fourth quarter of 2015, our net loss was $10 million ($(0.03) per share diluted), a decrease of $83 million compared to net earnings of $73 million ($0.18 per share diluted) in 2014, mainly due to:

 

•

greater losses on foreign exchange derivatives resulting from the weakening of the Canadian dollar

 

•

lower income tax recovery due to the reduction of our deferred tax asset in the US

 

•

higher impairment charges in 2015 ($210 million in 2015, $131 million in 2014)

partially offset by:

 

•

higher uranium gross profits resulting mainly from a higher average realized price and higher sales volumes

 

•

higher gross profits from our fuel services segment due to a higher average realized price

 

•

lower exploration expenditures

 

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•

the reduction of our provision related to the CRA litigation

In addition, in the fourth quarter of 2014 there was a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher net earnings in the fourth quarter of 2014 compared to the same period in 2015. The impact of the settlement was partially offset by the write-off of $41 million of assets under construction as a result of changes made to the scope of a number of projects in the fourth quarter of 2014.

On an adjusted basis, our earnings this quarter were $151 million ($0.38 per share diluted) compared to $205 million ($0.52 per share diluted) (non-IFRS measure, see page 8) in 2014, mainly due to:

 

•

a lower income tax recovery primarily due to the reduction of our deferred tax asset in the US

partially offset by:

 

•

higher uranium gross profits resulting mainly from a higher average realized price and higher sales volumes

 

•

higher gross profits from our fuel services segment mainly due to a higher average realized price

 

•

lower exploration expenditures

 

•

the reduction of our provision related to the CRA litigation

In addition, in the fourth quarter of 2014 there was a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher adjusted net earnings in the fourth quarter of 2014 compared to the same period in 2015.

Impairment charge on producing assets

During the fourth quarter of 2015, we recognized a $210 million impairment charge related to our Rabbit Lake operation. The impairment was due to increased uncertainty around future production sources for the Rabbit Lake mill as a result of the ongoing economic conditions. The amount of the charge was determined as the excess of carrying value over the recoverable amount. The recoverable amount of the mill was determined to be $69 million. See note 9 to the financial statements.

2015 market developments

As has been the case in recent years, a lot happened over the course of 2015, although the general state of the market did not see much change.

Making positive news for nuclear, as usual, was China. Not only did the country continue with its rapid reactor new build program and bring eight reactors online, but Chinese companies also signed agreements with Argentina, Romania and the UK for new reactors, illustrating the country’s commitment to nuclear and its intent to become a major international player in the nuclear industry.

Undoubtedly, the biggest headline of 2015 was the long-awaited first reactor restarts in Japan. Sendai units 1 and 2 were the first reactors in Japan to restart since 2013, and it is hoped they are the first of many to come.

New builds in the UK and US continued to be bright spots for the industry, in addition to a number of reactor life extensions approved in Japan, and the US, with utilities now considering additional extensions that could see reactor lives reaching 80 years.

However, these positive developments could not outweigh the more powerful influence of a continued sluggish global economy, geopolitical issues, concerns around growth in China, and flat electricity demand. These more general drivers had help from industry specific factors as well, such as slower new reactor construction, eight reactor shutdowns, the continued high level of inventories held by market participants, and France’s policy to reduce nuclear in their energy mix to 50% by 2025 becoming law.

In addition, supply performed relatively well, with only minor disruptions and one curtailment, unlike 2014, which saw six projects tempered or curtailed.

The end result was a market seemingly indifferent to the commotion of events that occurred throughout the year.

 

 

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CONTRACTING

Market contracting activity was modest. Spot volumes were normal, but long-term contracting was well below historical averages and current consumption levels—about half of current annual reactor consumption estimates, similar to 2014. Long-term contracting is a key factor in the timing of market recovery, and its pace will depend on the respective coverage levels, market views and risk appetite of both buyers and sellers.

JAPAN

The big news in Japan was the restart of Sendai units 1 and 2, which occurred in August and October. In addition, the court injunction against the two Takahama units was overturned in December, 2015, clearing the way for Takahama unit 3 to restart on January 29, 2016, with unit 4 expected to restart later in the first quarter. Ikata unit 3 has also cleared a safety inspection by the Nuclear Regulatory Authority, and four more units are in the final stages of approval. In all, three reactors are now in operation, while 23 remain under evaluation for restart.

Over the long term, Japan’s energy policy states that nuclear will make up 20 to 22% of the energy mix in the country. The billions of dollars in investment being made by Japan’s utilities suggest a high degree of confidence in reactors coming back online and meeting this target; however, public sentiment towards nuclear in Japan remains somewhat uncertain.

OTHER REGIONS

China’s remarkable nuclear growth program remains on track and the UK’s plans for new reactor construction continue to move forward. India and South Korea are also among several key regions growing their nuclear generation fleet.

In 2015, growth was tangible as 10 reactors came online—double that of 2014. These included the eight noted in China, one in Russia and one in South Korea. And seven more reactors began construction—six in China and one in the UAE, a formerly non-nuclear country with four reactors now under construction.

But, to round out the picture, eight units shut down. Five of these were in Japan, plus one in Sweden, one in Germany as part of its phase-out plans, and one in the UK—the last Magnox reactor operating in the world. In addition, there were announcements for future shutdowns in the US, where nuclear struggles to remain competitive in deregulated electricity markets and in the context of low natural gas prices.

One event that could have an effect on the future of nuclear in the US and other western countries is the UN Climate Conference COP-21 agreement, finalized in 2015. As a non-GHG emitter, nuclear could play a significant role in achieving climate change prevention goals.

Outlook for 2016

Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals, while maintaining the ability to respond to conditions as they evolve.

Our outlook for 2016 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 2015 Financial results by segment on page 12 for details.

 

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2016 FINANCIAL OUTLOOK

 

		CONSOLIDATED		URANIUM		FUEL SERVICES		NUKEM
Production		—		30.0 million lbs		8 to 9 million kgU		—
Delivery volume1		—		30 to 32 million lbs2		Decrease up to 5%		9 to 10 million lbs U3O8
Revenue compared to 20153		Decrease up to 5%		Decrease up to 5%4		Increase up to 5%		Increase 5% to 10%
Average unit cost of sales (including D&A)		—		Increase up to 5%5		Increase 10% to 15%		—
Direct administration costs compared to 20156		Increase 5% to 10%		—		—		—
Gross profit		—		—		—		Gross profit 4% to 5%
Exploration costs compared to 2015		—		Increase 15% to 20%		—		—
Tax rate7		Recovery of 25% to 30%		—		—		—
Capital expenditures		$320 million		—		—		—

 

1	Our 2016 outlook for delivery volume in our uranium and NUKEM segments does not include sales between our uranium, fuel services and NUKEM segments.

2	Our uranium delivery volume is based on the volumes we currently have commitments to deliver under contract in 2016.

3	For comparison of our 2016 outlook and 2015 results for revenue in our uranium and NUKEM segments, we do not include sales between our uranium, fuel services and NUKEM segments.

4	Based on a uranium spot price of $34.65 (US) per pound (the Ux spot price as of February 1, 2016), a long-term price indicator of $44.00 (US) per pound (the Ux long-term indicator on January 25, 2016) and an exchange rate of $1.00 (US) for $1.25 (Cdn).

5	This increase is based on the unit cost of sales for produced material and committed long-term purchases. If we make discretionary purchases in 2016, then we expect the overall unit cost of sales may be affected.

6	Direct administration costs do not include stock-based compensation expenses.

7	Our outlook for the tax rate is based on adjusted net earnings.

We expect consolidated revenue to decrease up to 5% in 2016, based on currently committed sales volumes, due to a planned decrease in uranium and fuel services sales volumes. If we make additional sales with deliveries in 2016, we would expect our revenue outlook to increase.

We expect administration costs (not including stock-based compensation) to be 5% to 10% higher compared to 2015 due to increased costs related to the northern collaboration agreements and increased project work. In 2016, we are continuing to negotiate new collaboration agreements with northern communities, which could result in additional one-time payments. Due to the uncertainty of the timing for the potential signing of agreements, the cost is not included in our outlook. If agreements are signed and there is an impact on our administrative costs, we will update our outlook.

We expect exploration expenses to be about 15% to 20% higher than they were in 2015 due to increased exploration activity at Cigar Lake.

On an adjusted net earnings basis, we expect a tax recovery of 25% to 30% in 2016 from our uranium, fuel services and NUKEM segments.

Our consolidated tax rate is a blend of the statutory rates applicable to taxable income earned or tax losses incurred in Canada and in our foreign subsidiaries. We have a global customer base and we have established a marketing and trading structure involving foreign subsidiaries, which entered into various intercompany purchase and sale arrangements, as well as uranium purchase and sale agreements with third parties. Cameco and its subsidiaries made reasonable efforts to put arm’s-length transfer pricing arrangements in place, and these arrangements expose the parties to the risks and rewards accruing to them under these contracts. The intercompany contract prices are generally comparable to those established in comparable contracts between arm’s-length parties entered into at that time.

This year, many of the existing intercompany purchase and sale arrangements in our portfolio expire. We have started to replace these contracts and will continue to put new intercompany arrangements in place, which, as the existing arrangements did, will reflect the market at the time they are signed.

 

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As a result, in 2017, we expect our consolidated tax rate will transition to a modest expense, and trend toward a tax expense of approximately 20% over the next five years. The actual effective tax rate will vary from year-to-year, primarily due to the actual distribution of earnings among jurisdictions and the market conditions at the time transactions occur under both our intercompany and third-party purchase and sale arrangements.

ROYALTIES

We pay royalties on the sale of all uranium extracted at our mines in the province of Saskatchewan. Two types of royalties are paid:

 

•

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

 

•

Profit royalty: a 10% royalty is charged on profit up to and including $22.70/kg U3O8 ($10.30/lb) and a 15% royalty is charged on profit in excess of $22.70/kg U3O8. Profit is determined as revenue less certain operating, exploration, reclamation and capital costs. Both exploration and capital costs are deductible at the discretion of the producer.

As a resource corporation in Saskatchewan, we also pay a corporate resource surcharge of 3% of the value of resource sales.

During the period from 2013 to 2015, transitional rules for the new profit royalty regime were applied whereby only 50% of capital costs were deductible. The remaining 50% was accumulated and will now be deductible beginning in 2016. In addition, the capital allowance related to Cigar Lake under the previous system was grandfathered and is also now deductible beginning in 2016. Based on the expected application of transitional and grandfathered capital allowance deductions, we anticipate that only the first tier of the profit royalty (10%) will apply in 2016 and 2017. As capital pools are depleted, we expect to also be subject to the top tier of the profit royalty (15%) in 2018.

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)		2015 PLAN1				2015 ACTUAL				2016 PLAN
Sustaining capital
McArthur River/Key Lake			20				16				30
Cigar Lake			10				9				25
Rabbit Lake			35				33				25
US ISR			5				7				5
Inkai			5				1				5
Fuel services			15				13				20
Other			5				5				5
Total sustaining capital			95				84				115
Capacity replacement capital
McArthur River/Key Lake			95				96				55
Cigar Lake			25				26				20
Rabbit Lake			—				—				10
US ISR			30				27				20
Inkai			15				19				15
Total capacity replacement capital			165				168				120
Growth capital
McArthur River/Key Lake			15				13				40
Cigar Lake			90				81				30
Inkai			15				11				10
Fuel services			5				1				5
Other			—				1				—
Total growth capital			125				107				85
Total uranium & fuel services			385	1			359				320

 

1	Capital spending outlook was updated to $385 million in our third quarter MD&A.

 

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Outlook for investing activities

 

CAMECO’S SHARE ($ MILLIONS)		2017 PLAN		2018 PLAN
Total uranium & fuel services		300-350		250-300
Sustaining capital		135-155		95-110
Capacity replacement capital		135-150		145-160
Growth capital		30-45		10-25

We expect total capital expenditures for uranium and fuel services to decrease by about 11% in 2016.

Major sustaining, capacity replacement and growth expenditures in 2016 include:

 

•

McArthur River/Key Lake – At McArthur River, the largest projects are the expansion of freeze capacity and mine development. Other projects include site facility and equipment purchases. At Key Lake, work will be done to expand capacity in the solvent extraction and crystallization circuits of the mill.

 

•

US in situ recovery (ISR) – wellfield construction represents the largest portion of our expenditures in the US.

 

•

Rabbit Lake – At Eagle Point, the largest component is mine development, along with mine equipment upgrades and purchases. At the mill, we plan to optimize tailings capacity and work on various mill facility and equipment replacements.

 

•

Cigar Lake – Work to expand freezing capacity makes up the largest portion of capital at the Cigar Lake site. We are also paying our share of the costs to modify and expand the McClean Lake mill.

We previously expected to spend between $350 million and $400 million in 2017. We now expect to spend between $300 million and $350 million in 2017. Due to the continued market uncertainty, we have reduced growth capital to focus on our tier-one properties.

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 21 and 22. Our actual capital expenditures for future periods may be significantly different.

REVENUE, CASH FLOW AND EARNINGS SENSITIVITY ANALYSIS

For 2016:

 

•

An increase of $5 (US) per pound in each of the Ux spot price ($34.65 (US) per pound on February 1, 2016) and the Ux long-term price indicator ($44.00 (US) per pound on January 25, 2016) would change revenue by $72 million and net earnings by $56 million. Conversely, a decrease of $5 (US) per pound would decrease revenue by $69 million and net earnings by $54 million.

 

•

A one cent change in the value of the Canadian dollar versus the US dollar would change adjusted net earnings by $8 million and cash flow by $1 million, with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact.

URANIUM SEGMENT OUTLOOK

We expect to produce 30.0 million pounds in 2016 and have commitments under long-term contracts to purchase approximately 9 million pounds.

Based on the contracts we have in place, and not including sales between our segments, we expect to deliver between 30 million and 32 million pounds of U₃O₈ in 2016. We expect the unit cost of sales to be up to 5% higher than in 2015, primarily due to the planned purchases during the year. If we make additional discretionary purchases in 2016 at a cost different than our other sources of supply, then we expect the overall unit cost of sales to be affected.

We expect revenue to be up to 5% lower than in 2015 as a result of an expected decrease in deliveries, not including sales between our segments, partially offset by a higher average realized price.

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries. As a result, our quarterly delivery patterns and, therefore, our sales volumes and revenue can vary significantly as shown below. We expect the quarterly distribution of uranium deliveries in 2016 to be weighted to the second half of the year. However, not all delivery notices have been received to date and the expected delivery pattern could change. Typically, we receive notices six months in advance of the requested delivery date.

 

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PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

The following table is not a forecast of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table. It is designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2015 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, 2015, and none of the assumptions we list below change.

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

Expected realized uranium price sensitivity under various spot price assumptions

 

(rounded to the nearest $1.00)
SPOT PRICES ($US/lb U3O8)		$20				$40				$60				$80				$100				$120				$140
2016			41				46				56				65				75				84				93
2017			39				46				56				67				78				87				94
2018			39				47				58				69				80				90				97
2019			39				47				59				70				79				88				94
2020			42				49				59				70				79				86				93

The table illustrates the mix of long-term contracts in our December 31, 2015 portfolio, and is consistent with our marketing strategy. It has been updated to reflect deliveries made and contracts entered into up to December 31, 2015.

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:

 

FUEL SERVICES OUTLOOK

In 2016, we plan to produce 8 million to 9 million kgU, and we expect sales volumes, not including intersegment sales, to be up to 5% lower than in 2015. Overall revenue is expected to increase by up to 5% as lower sales volumes will be more than offset by an increase in the average realized price. We expect the average unit cost of sales (including D&A) to increase by 10% to 15%; therefore, overall gross profit will decrease as a result.

NUKEM OUTLOOK

For 2016, NUKEM expects to deliver between 9 million and 10 million pounds of uranium. Total revenue and unit cost of sales, not including intersegment sales, is expected to increase by 5% to 10% compared to 2015; however, the overall gross profit percentage is expected to be slightly lower than 2015 at 4% to 5%.

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

 

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better reflect the underlying financial performance for the reporting period. The adjusted earnings measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period, and adjusted for impairment charges, the write-off of assets, NUKEM inventory write-down, gain on interest in BPLP (after tax), and income taxes on adjustments.

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

To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the years ended 2015 and 2014, and three months ended December 31, 2015 and December 31, 2014.

 

		THREE MONTHS ENDED DECEMBER 31								YEAR ENDED DECEMBER 31
($ MILLIONS)		2015				2014				2015				2014
Net earnings (loss) attributable to equity holders			(10	)			73				65				185
Adjustments
Adjustments on derivatives (pre-tax)			10				10				166				47
NUKEM purchase price inventory recovery			—				(4	)			(3	)			(5	)
Impairment charges			210				131				215				327
Income taxes on adjustments			(59	)			(46	)			(99	)			(56	)
Write-off of assets			—				41				—				41
Gain on interest in BPLP (after tax)			—				—				—				(127	)
Adjusted net earnings			151				205				344				412

TRANSFER PRICING DISPUTES

We have been reporting on our transfer pricing disputes with CRA since 2008, when it originated, and with the United States Internal Revenue Service (IRS) since the first quarter of 2015. Below, we discuss the general nature of transfer pricing disputes and, more specifically, the ongoing disputes we have.

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

 

•

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

 

•

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

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

For the years 2003 to 2010, CRA has shifted CEL’s income (as recalculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2009, transfer pricing penalties. There has not yet been a decision regarding a transfer pricing penalty for 2010. The IRS also allocated a portion of CEL’s income for the years 2009 through 2012 to the US, resulting in such income being taxed in multiple jurisdictions. Taxes of approximately $320 million for the 2003 – 2015 years have already been paid in a jurisdiction outside Canada and the US. Bilateral international tax treaties contain provisions that generally seek to prevent taxation of the same income in both countries. As such, in connection with these disputes, we are considering our options, including remedies under international tax treaties that would limit double taxation; however, there is a risk that we will not be successful in eliminating all potential double taxation. The expected income adjustments under our tax disputes are represented by the amounts claimed by CRA and IRS and are described below.

 

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CRA dispute

Since 2008, CRA has disputed our corporate structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements. To the end of 2014, we received notices of reassessment for our 2003 through 2009 tax returns, and, in the fourth quarter of 2015, we received a notice of reassessment for our 2010 tax year. We have recorded a cumulative tax provision of $50 million (September 30, 2015 - $92 million), where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through 2015. We have reduced the provision to reflect management’s revised estimate, which takes into account additional contract information. We are confident that we will be successful in our case and continue to believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

For the years 2003 through 2010, CRA issued notices of reassessment for approximately $3.4 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $1.1 billion. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229 million. The Canadian income tax rules include provisions that require larger companies like us to remit or otherwise secure 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions, we have paid a net amount of $232 million cash. In addition, we have provided $332 million in letters of credit (LC) to secure 50% of the cash taxes and related interest amounts reassessed in 2015. The amounts paid or secured are shown in the table below.

 

YEAR PAID ($ MILLIONS)		CASH TAXES				INTEREST AND INSTALMENT PENALTIES				TRANSFER PRICING PENALTIES				TOTAL				CASH REMITTANCE				SECURED BY LC
Prior to 2013			—				13				—				13				13				—
2013			1				9				36				46				46				—
2014			106				47				—				153				153				—
2015			202				71				79				352				20				332
Total			309				140				115				564				232				332

Using the methodology we believe CRA will continue to apply, and including the $3.4 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $7.0 billion of additional income taxable in Canada for the years 2003 through 2015, which would result in a related tax expense of approximately $2.1 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2009. As a result, we estimate that cash taxes and transfer pricing penalties for these years would be between $1.65 billion and $1.70 billion. In addition, we estimate there would be interest and instalment penalties applied that would be material to us. While in dispute, we would be responsible for remitting or otherwise providing security for 50% of the cash taxes and transfer pricing penalties (between $825 million and $850 million), plus related interest and instalment penalties assessed, which would be material to us.

Under the Canadian federal and provincial tax rules, the amount required to be paid or secured each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers. Recently, the CRA decided to disallow the use of any loss carry-backs for any transfer pricing adjustment, starting with the 2008 tax year. This does not impact the anticipated income tax expense for a particular year, but does impact the timing of any required security or payment. As noted above, for the 2010 tax year, as an alternative to paying cash, we used letters of credit to satisfy our obligations related to the reassessed income tax and related interest amounts. We expect to be able to continue to provide security in the form of letters of credit to satisfy these requirements. The estimated amounts summarized in the table below reflect actual amounts paid or secured and estimated future amounts owing based on the actual and expected reassessments for the years 2003 through 2015, and include the expected timing adjustment for the inability to use any loss carry-backs starting in 2008. We will update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2015.

 

$ MILLIONS		2003-2015				2016-2017				2018-2023				TOTAL
50% of cash taxes and transfer pricing penalties paid, secured or owing in the period
Cash payments			156				155 - 180				30 - 55				335 - 360
Secured by letters of credit			264				95 - 120				20 - 45				425 - 450
Total paid1			420				255 - 280				65 - 90				825 - 850

 

1	These amounts do not include interest and instalment penalties, which totaled approximately $140 million to December 31, 2015.

 

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In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted, including the $564 million already paid or otherwise secured to date.

We are expecting the trial for the 2003, 2005 and 2006 reassessments to commence during the week of September 26, 2016, with final arguments in April 2017. If this timing is adhered to, we expect to receive a Tax Court decision within six to 18 months after the trial is complete.

IRS dispute

In the fourth quarter of 2015, we received a Revenue Agents Report (RAR) from the IRS for the tax years 2010 to 2012. Similar to the 2009 RAR received in the first quarter of 2015, the IRS is challenging the transfer pricing used under certain intercompany transactions pertaining to the 2010 to 2012 tax years for certain of our US subsidiaries. The 2009 and 2010 to 2012 RARs list the adjustments proposed by the IRS and calculate the tax and any penalties owing based on the proposed adjustments.

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

 

•

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

 

•

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

The proposed adjustments result in an increase in taxable income in the US of approximately $419 million (US) and a corresponding increased income tax expense of approximately $122 million (US) for the 2009 through 2012 taxation years, with interest being charged thereon. In addition, the IRS proposed cumulative penalties of approximately $8 million (US) in respect of the adjustment.

We believe that the conclusions of the IRS in the RARs are incorrect and we are contesting them in an administrative appeal, during which we are not required to make any cash payments. Until this matter progresses further, we cannot provide an estimation of the likely timeline for a resolution of the dispute.

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

Overview of disputes

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

 

				CRA				IRS
Basis for dispute		•		Corporate structure/governance		•		Income earned on sales of uranium by the US mines to CEL is inadequate
		•		Transfer pricing methodology used for certain intercompany uranium sale and purchase agreements		•		Compensation earned by Cameco Inc., one of our US subsidiaries, is inadequate
		•		Allocates Cameco Europe Ltd. (CEL) income (as adjusted) for 2003 through 2010 to Canada (same income we paid tax on in foreign jurisdictions and includes income that IRS is proposing to tax)		•		Allocates a portion of CEL’s income for the years 2009 through 2012 to the US (a portion of the same income we paid tax on in foreign jurisdictions and which the CRA is proposing to tax)
Years under consideration		•		CRA reassessed 2003 to 2010		•		IRS has proposed adjustments for 2009 through 2012
		•		Auditing 2011 to 2012
Timing of resolution		•		Expect our appeal of the 2003, 2005 and 2006 reassessments to commence during the week of September 26, 2016, with final arguments expected in April 2017		•		Contesting proposed adjustments in an administrative appeal
		•		Expect Tax Court decision six to 18 months after completion of trial		•		We cannot yet provide an estimate as to the timeline for resolution
Required payments		•		Expect to provide security in form of letters of credit and/or make cash payments for 50% of cash taxes, interest and penalties as reassessed		•		No security or cash payments required while under administrative appeal
		•		Paid $232 million in cash to date
		•		Secured $332 million using letters of credit

 

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

This discussion of our expectations relating to our tax disputes with CRA and IRS and future tax reassessments by CRA and IRS is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 21 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.

 

 

2015 financial results by segment

Uranium results

 

						THREE MONTHS ENDED DECEMBER 31												YEAR ENDED DECEMBER 31
HIGHLIGHTS						2015				2014				CHANGE				2015				2014				CHANGE
Production volume (million lbs)							9.6				8.2				17	%			28.4				23.3				22	%
Sales volume (million lbs)1							11.2				10.7				5	%			32.4				33.9				(4	)%
Average spot price		($	US/lb	)			35.45				37.13				(5	)%			36.55				33.21				10	%
Average long-term price		($	US/lb	)			44.00				48.00				(8	)%			46.29				46.46				—
Average realized price		($	US/lb	)			46.36				50.57				(8	)%			45.19				47.53				(5	)%
		($	Cdn/lb	)			61.24				56.78				8	%			57.58				52.37				10	%
Average unit cost of sales (including D&A)		($	Cdn/lb	)			38.25				34.27				12	%			38.83				34.64				12	%
Revenue ($ millions)1							687				606				13	%			1,866				1,777				5	%
Gross profit ($ millions)							257				240				7	%			608				602				1	%
Gross profit (%)							37				40				(8	)%			33				34				(3	)%

 

1

Includes sales and revenue between our uranium, fuel services and NUKEM segments (17,000 pounds in sales and revenue of $0.5 million in Q4 2015, 400,000 pounds in sales and revenue of $15 million in Q4 2014, and 32,000 pounds in sales and revenue of $1.0 million in 2015, 1.4 million pounds in sales and revenue of $48 million in 2014).

FOURTH QUARTER

Production volumes this quarter were 17% higher compared to the fourth quarter of 2014, mainly as a result of higher production from the rampup of Cigar Lake production, offset by lower production at McArthur River/Key Lake, Rabbit Lake and our US ISR operations. See Our operations starting on page 15 for more information.

 

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Uranium revenues were up 13% due to a 5% increase in sales volumes, which represents normal quarterly variance in our delivery schedule, and an 8% increase in the average realized price.

Average spot and long-term prices decreased, as did our US dollar average realized price due to lower prices under fixed-price contracts, and the mix of market and fixed contracts. However, the effect of foreign exchange resulted in an 8% higher Canadian dollar average realized price than the prior year. In the fourth quarter of 2015, our realized foreign exchange rate was $1.32 compared to $1.12 in the prior year.

Total cost of sales (including D&A) increased by 17% ($429 million compared to $366 million in 2014). This was the result of a 12% increase in the average unit cost of sales and a 5% increase in sales volumes.

The unit cost of sales increased due to an increase in the volume of material purchased throughout the year at prices higher than our average cost of inventory and an increase in the unit production costs related to the addition of higher cost production from Cigar Lake during rampup.

The net effect was a $17 million increase in gross profit for the quarter.

FULL YEAR

Production volumes in 2015 increased by 22% compared to 2014. Lower production at our US ISR operations was more than offset by the rampup of Cigar Lake production. See Our operations starting on page 15 for more information.

Uranium revenues this year were up 5% compared to 2014 due to an increase of 10% in the Canadian dollar average realized price, partially offset by a decrease in sales volumes of 4%. The spot price for uranium averaged $36.55 (US) per pound in 2015, an increase of 10% compared to the 2014 average price of $33.21 (US) per pound; however, our US dollar average realized price was lower mainly due to lower prices under fixed price contracts. The effect of foreign exchange resulted in a higher Canadian dollar average realized price than in the prior year. The realized foreign exchange rate was $1.27 compared to $1.10 in 2014.

Total cost of sales (including D&A) increased by 7% ($1.26 billion compared to $1.18 billion in 2014) due to higher unit cost of sales offset by lower sales volumes. The higher unit cost of sales was mainly the result of an increase in the volume of material purchased at prices higher than our average cost of inventory, and an increase in unit production costs related to the addition of higher costs from Cigar Lake during rampup.

The net effect was a $6 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.

 

		THREE MONTHS ENDED DECEMBER 31												YEAR ENDED DECEMBER 31
($CDN/LB)		2015				2014				CHANGE				2015				2014				CHANGE
Produced
Cash cost			16.04				14.19				13	%			20.62				18.66				11	%
Non-cash cost			10.96				7.15				53	%			11.51				9.30				24	%
Total production cost			27.00				21.34				27	%			32.13				27.96				15	%
Quantity produced (million lbs)			9.6				8.2				17	%			28.4				23.3				22	%
Purchased
Cash cost1			43.65				39.03				12	%			46.02				38.17				21	%
Quantity purchased (million lbs)			3.2				3.7				(14	)%			12.5				7.1				76	%
Totals
Produced and purchased costs1			31.16				26.84				16	%			36.38				30.34				20	%
Quantities produced and purchased (million lbs)			12.8				11.9				8	%			40.9				30.4				35	%

 

1

In the fourth quarter of 2015, cash costs of purchased material were $33.79 (US) per pound compared to $35.05 (US) per pound in the same period in 2014. In the fourth quarter of 2015, the exchange rate on purchases averaged $1.00 (US) for $1.29 (Cdn) compared to $1.00 (US) for $1.11 (Cdn) during the same period in 2014. Cash costs of purchased material in 2015 were $36.57 (US) per pound compared to $34.51 (US) per pound in 2014. In 2015, the exchange rate on purchases averaged $1.00 (US) for $1.26 (Cdn) compared to $1.00 (US) for $1.11 (Cdn) in 2014.

 

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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 years ended 2015 and 2014 and three months ended December 31, 2015 and December 31, 2014 as reported in our financial statements.

Cash and total cost per pound reconciliation

 

		THREE MONTHS ENDED								YEAR ENDED
		DECEMBER 31								DECEMBER 31
($ MILLIONS)		2015				2014				2015				2014
Cost of product sold			328.3				269.0				989.2				902.8
Add / (subtract)
Royalties			(49.5	)			(34.5	)			(116.5	)			(91.2	)
Standby charges			—				—				—				(24.8	)
Other selling costs			(6.7	)			(2.3	)			(13.8	)			(9.0	)
Change in inventories			21.5				28.5				301.8				(71.9	)
Cash operating costs (a)			293.6				260.7				1,160.7				705.9
Add / (subtract)
Depreciation and amortization			100.9				96.7				269.1				272.6
Change in inventories			4.3				(38.0	)			58.1				(56.2	)
Total operating costs (b)			398.8				319.4				1,487.9				922.3
Uranium produced & purchased (million lbs) (c)			12.8				11.9				40.9				30.4
Cash costs per pound (a ÷ c)			22.94				21.91				28.38				23.22
Total costs per pound (b ÷ c)			31.16				26.84				36.38				30.34

Fuel services results

 

(includes results for UF6, UO2 and fuel fabrication)
						THREE MONTHS ENDED												YEAR ENDED
						DECEMBER 31												DECEMBER 31
HIGHLIGHTS						2015				2014				CHANGE				2015				2014				CHANGE
Production volume (million kgU)							3.4				2.7				26	%			9.7				11.6				(16	)%
Sales volume (million kgU)1							4.5				7.4				(39	)%			13.6				15.5				(12	)%
Average realized price		($	Cdn/kgU	)			21.88				16.92				29	%			23.37				19.70				19	%
Average unit cost of sales (including D&A)		($	Cdn/kgU	)			17.18				14.78				16	%			18.87				17.24				9	%
Revenue ($ millions)1							99				125				(21	)%			319				306				4	%
Gross profit ($ millions)							21				16				31	%			61				38				61	%
Gross profit (%)							21				13				62	%			19				12				58	%

 

1

Includes sales and revenue between our uranium, fuel services and NUKEM segments (339,000 kgU in sales and revenue of $2.9 million in Q4 2015, 0.5 million kgU in sales and revenue of $4 million in Q4 2014, and 339,000 kgU in sales and revenue of $2.9 million in 2015, 0.5 million kgU in sales and revenue of $4 million in 2014).

FOURTH QUARTER

Total revenue decreased by 21% due to a 39% decrease in sales volumes, partially offset by a 29% increase in average realized price.

 

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The total cost of sales (including D&A) decreased by 28% ($78 million compared to $109 million in the fourth quarter of 2014) mainly due to a 39% decrease in sales volumes, partially offset by an increase of 16% in the average unit cost of sales, primarily as a result of the mix of products sold.

The net effect was a $5 million increase in gross profit.

FULL YEAR

Total revenue increased by 4% due to a 19% increase in the realized price, partially offset by a 12% decrease in sales volumes.

The total cost of products and services sold (including D&A) decreased by 4% compared to 2014 ($258 million compared to $268 million in 2014), as a 12% decrease in sales volumes was partially offset by a 9% increase in the average unit cost of sales (including D&A). When compared to 2014, the average unit cost of sales was 9% higher due to the mix of fuel services products sold.

The net effect was a $23 million increase in gross profit.

NUKEM results

 

						THREE MONTHS ENDED												YEAR ENDED
						DECEMBER 31												DECEMBER 31
HIGHLIGHTS						2015				2014				CHANGE				2015				2014				CHANGE
Sales volume U3O8 (million lbs)1							3.7				3.4				9	%			10.7				8.1				32	%
Average realized price		($	Cdn/lb	)			52.22				52.12				—				48.82				44.90				9	%
Cost of product sold (including D&A)							186				156				19	%			512				327				57	%
Revenue ($ millions)1							192				159				21	%			554				349				59	%
Gross profit ($ millions)							6				3				100	%			42				22				91	%
Gross profit (%)							3				2				50	%			8				6				33	%

 

1	Includes sales and revenue between our uranium, fuel services and NUKEM segments (nil in Q4 2015, 1.1 million pounds in sales and revenue of $43 million in Q4 2014, and 0.9 million pounds in sales and revenue of $19.3 million in 2015, 1.1 million pounds in sales and revenue of $43 million in 2014).

FOURTH QUARTER

NUKEM delivered 3.7 million pounds of uranium, an increase of 0.3 million pounds compared to 2014. NUKEM revenues amounted to $192 million compared to $159 million in 2014 due to an increase in volumes delivered.

Gross profit percentage was 3% in the fourth quarter of 2015, compared to 2% in the fourth quarter of 2014.

The net effect was a $3 million increase in gross profit.

FULL YEAR

During 2015, NUKEM delivered 10.7 million pounds of uranium, an increase of 2.6 million pounds compared to the previous year due to an increase in market activity. Revenues from NUKEM amounted to $554 million, 59% higher than in 2014 as a result of higher sales volumes and an increase in the average realized price, mainly due to weakening of the Canadian dollar. Gross profit percentage was 8% for 2015, compared to 6% for 2014.

The net effect was a $20 million increase in gross profit.

Our operations

 

		THREE MONTHS ENDED								YEAR ENDED
CAMECO SHARE		DECEMBER 31								DECEMBER 31
(MILLION LBS)		2015				2014				2015				2014				2015 PLAN1				2016 PLAN
McArthur River/Key Lake			3.8				4.4				13.3				13.3				13.7				14.0
Cigar Lake			2.3				0.2				5.7				0.2				4.0 -5.0				8.0	2
Inkai			1.1				0.7				3.4				2.9				3.0				3.0
Rabbit Lake			2.0				2.1				4.2				4.2				3.9				3.6
Smith Ranch-Highland			0.3				0.6				1.4				2.1				1.4				1.2
Crow Butte			0.1				0.2				0.4				0.6				0.3				0.2
Total			9.6				8.2				28.4				23.3				26.3 - 27.3				30.0	2

 

1	We updated our initial 2015 plan for Cigar Lake (to 5 million pounds, from between 3 and 4 million pounds) in our Q3 MD&A.

2	Our 2016 plan for packaged production from Cigar Lake is subject to regulatory approval for an annual production limit increase at the McClean Lake mill. See Cigar Lake starting on page 17 for more information.

 

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Production Outlook

We remain focused on taking advantage of the long-term growth we see coming in our industry, while maintaining the ability to respond to market conditions as they evolve. Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals in order to increase long-term shareholder value.

We plan to:

 

•

ensure continued safe, reliable, low-cost production from our tier-one assets – McArthur River/Key Lake, Cigar Lake and Inkai

 

•

complete rampup of production at Cigar Lake

 

•

seek to expand production at McArthur River/Key Lake in conjunction with market signals

 

•

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

 

•

maintain our low-cost advantage by focusing on execution and operational excellence

MCARTHUR RIVER/KEY LAKE

Production

Production from McArthur River/Key Lake was 19.1 million pounds; our share was 13.3 million pounds. This was 3% lower than our forecast for the year due to unplanned maintenance outages to repair the calciner at Key Lake. Annual production was unchanged from 2014.

Licensing and production capacity

In 2015, the CNSC approved our application to increase McArthur River’s licensed annual production to 25 million pounds (100% basis) to allow flexibility to match the approved Key Lake mill capacity. The licence conditions handbooks for these operations now allow both operations to produce up to 25 million pounds (100% basis) per year.

Key Lake extension and McArthur River production expansion

In support of our strategy to maintain the flexibility to respond to market conditions as they evolve, we continue to advance projects that are necessary to sustain and increase production when the market signals that additional production is needed.

The Key Lake mill began operating in 1983 and we continue to upgrade circuits with new technology to simplify operations and improve environmental performance. The extension project involved increasing our tailings capacity and the mill’s nominal annual production rate to closely follow production from the McArthur River mine. As part of the mill upgrades, we continue to construct and commission a new calciner circuit, and expect to begin operating with the new calciner in 2016. The existing calciner circuit will remain in place until operational reliability of the new calciner is achieved. The calciner replacement project was planned in a way that temporarily allows us to use either calciner, which will help to mitigate risks to our production rate during the commissioning phase. In order to increase production at Key Lake, we also need to optimize and expand the solvent extraction and crystallization circuits in the mill (projects planned for 2017).

At McArthur River, we must continue to successfully transition into new mine areas through mine development and investment in support infrastructure. We plan to:

 

•

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

 

•

expand the concrete distribution systems and batch plant capacity

New mining areas

New mining zones and increased mine production require increased freeze capacity and ventilation. In 2015, we continued to upgrade our electrical infrastructure on surface as part of our plan to address these future needs. We advanced groundworks to prepare for the next freeze plant, which is scheduled to begin freezing the south end of the orebody (zone 4) in 2017.

We also made changes in shaft 2 to increase air flow, resulting in a 15% to 20% improvement in ventilation capacity. The improved ventilation eliminates the need for a new ventilation shaft to support a higher production rate.

 

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Tailings capacity

We expect to have sufficient tailings capacity to mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

PLANNING FOR THE FUTURE AT MCARTHUR RIVER/KEY LAKE

Production

We plan to produce 20.0 million pounds in 2016; our share is 14.0 million pounds.

Expansion progress

As previously disclosed in our 2012 Technical Report, we plan to reach an annual capacity of 22 million pounds by 2018. The capital required to do so is shown in our 2016 capital spending plan, and in our outlook for investing activities in 2017 and 2018, beginning on page 6.

As we increase to 22 million pounds per year, we will optimize the capacity of both the Key Lake mill and McArthur River mine with a view to further increasing production to 25 million pounds per year (100% basis), as market conditions improve. Using this approach, we do not expect significant additional growth capital will be required to increase from annual production of 22 million pounds to an annual rate of 25 million pounds. We expect that this paced approach will allow us to extract maximum value from the operation as the market transitions.

Exploration

In 2015, underground drilling further delineated the zone A mineral resources. Underground definition drilling of zone B will be conducted in 2016 and 2017 to provide the information required for engineering work to develop more detailed mining plans.

CIGAR LAKE

Production

Total packaged production from Cigar Lake was 11.3 million pounds U₃O₈; our share was 5.7 million pounds. The operation exceeded our forecast of 10 million pounds (100% basis) as a result of higher productivity and our intention to adjust annual production as necessary, based on our operating experience during rampup.

During the year, we:

 

•

completed commissioning of the equipment required to operate three JBS units at a production scale

 

•

brought on additional slurry haul trucks to ensure a sufficient quantity of ore slurry can be transported to the McClean Lake mill

 

•

completed final commissioning of underground processing circuits and updated our production rampup plan based on commissioning experience

 

•

modified mine and project plans to reflect our decision to exclusively freeze from surface

 

•

declared commercial production

Commercial production

Commercial production signals a transition in the accounting treatment for costs incurred at the mine. Cigar Lake met all of the criteria for commercial production, including cycle time and process specifications, in the second quarter of 2015. Therefore, effective May 1, 2015, we began charging all production costs, including depreciation, to inventory and subsequently recognizing them in cost of sales as the product is sold.

Underground development

As a result of our decision to exclusively use surface freezing going forward, and the resulting change in the mine plan, the bulk of the development and freeze drilling required for mining in 2016 is already complete. We are continuing to plan for future expansion of surface freezing infrastructure in late 2016.

 

- 17 -

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McClean Lake mill update

Additional estimated expenditures of $50 million (100% basis, our share $25 million) are expected to be required at the McClean Lake mill in 2016, primarily to complete upgrades in the tailings neutralization area in support of the continued rampup to full production of 18 million pounds per year.

PLANNING FOR THE FUTURE AT CIGAR LAKE

Production

In 2016, we expect to produce 16.0 million packaged pounds at Cigar Lake; our share is 8.0 million pounds.

In 2016, we also expect to:

 

•

extend the current surface freeze pad and advance planning for freeze plant infrastructure expansion to support future production

 

•

advance underground development according to the new mine plan and backfill drifts no longer required for underground freezing operations

 

•

continue ramping up towards the planned full annual production rate of 18 million pounds (100% basis) in 2017

Exploration

We are planning to conduct delineation drilling from surface to confirm and upgrade resources contained in the western portion of the deposit. Approximately 65,000 metres of diamond drilling is planned over a three-year period, starting in 2016, in order to complete a detailed geological and geotechnical interpretation, a resource estimate, and a technical study for the western portion of the deposit.

Rampup schedule

In 2017, we expect to reach full annual production of 18 million pounds (100% basis, 9 million pounds our share).

The McClean Lake mill’s operating licence currently has an annual production limit of 13 million pounds. AREVA has submitted an application to the CNSC to increase the mill’s licensed annual production limit; our 2016 and 2017 production outlook for Cigar Lake is therefore subject to AREVA securing the regulatory approvals necessary to increase mill production.

Labour relations

The current collective agreement between AREVA and unionized employees at the McClean Lake operation expires in May 2016. There is risk to our 2016 and 2017 production outlook for Cigar Lake if AREVA is unable to reach an agreement and there is a labour dispute.

INKAI

Production

Total production from Inkai was 5.8 million pounds; our share was 3.4 million pounds. Production was 17% higher than our production in 2014. During 2015, the subsoil use law in Kazakhstan was amended to allow producers to produce within 20% (above or below) their licensed capacity in a year. As a result, Inkai produced 5.8 million pounds in 2015, 11% higher than its licensed capacity. The increase in production was the result of a higher head grade and an increase in wellfield development efficiency compared to 2014.

Project funding

As of December 31, 2015, Inkai had fully repaid the outstanding loan under our agreement to fund its project development costs related to blocks 1 and 2. In 2015, Inkai paid the remaining $0.8 million (US) in interest on the loan and repaid $55 million (US) of principal.

We are currently advancing funds for Inkai’s work on block 3 and, as of December 31, 2015, the principal amounted to $148 million (US). Under the loan agreement, Inkai is to repay Cameco from the net sales proceeds from the sale of production from block 3.

 

- 18 -

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Production expansion

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

 

•

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

 

•

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

Kazatomprom is pursuing a strategic objective to develop uranium processing capacity in Kazakhstan to complement its leading uranium mining operations. Their primary focus is now on uranium refining, which is an intermediate step in the uranium conversion process. A Nuclear Co-operation Agreement between Canada and Kazakhstan is in place, providing the international framework necessary for applying to the two governments for the required licences and permits. We expect to pursue further expansion of production at Inkai at a pace measured to market opportunities. Discussions continue with Kazatomprom.

Block 3 exploration

In 2015, Inkai completed construction of the test leach facility and began pilot production from test wellfields, as well as advancing work on a preliminary appraisal of the mineral potential of block 3 according to Kazakhstan standards.

Block 3 licence extension

The block 3 test leach facility is now operational and state commissioning of the test wellfields was accomplished during 2015. Our application for an extension of the block 3 evaluation period is still pending final approval from the Ministry of Energy of the Republic of Kazakhstan. Inkai continues working on the final appraisal of the mineral potential of block 3 according to Kazakhstan standards. Although a number of extensions of the licence term have been granted by Kazakh regulatory authorities in the past, there is no assurance that a further extension will be granted. Without such extension, there is a risk we could lose our rights to block 3, and a risk we will not be compensated for the funds we advanced to Inkai to fund block 3 activities.

PLANNING FOR THE FUTURE AT INKAI

Production

We expect total production from blocks 1 and 2 to be 5.2 million pounds in 2016; our share is 3.0 million pounds. We expect to maintain production at this level until the potential growth plans are finalized with Kazatomprom.

Block 3 exploration

In 2016, Inkai expects to continue with pilot production from the test leach facility and to continue working on a final appraisal of the mineral potential according to Kazakhstan standards.

RABBIT LAKE

Production

Production this year was unchanged from our 2014 production as a result of planned timing of production stopes, coupled with slightly improved ore grades.

Development and production continued at the Eagle Point mine. At the mill, we continued to improve the efficiency of the mill operation schedule.

Temporary mining restrictions

On December 17, 2015, we announced that underground mining activities at Eagle Point were being restricted due to a rock fall in an inactive area of the mine. As a precautionary measure, non-essential personnel were removed from the mine while the condition of the affected area was evaluated. Mine production was suspended, although milling of previously mined and transported ore continued through to year end.

 

- 19 -

---

The assessment determined that repairs were necessary to support the ground in the affected area of the mine. The repairs were completed, along with some further assessment of stability in other areas of the mine. The mine was reopened and normal operations resumed on February 3, 2016.

PLANNING FOR THE FUTURE AT RABBIT LAKE

Production

We expect to produce 3.6 million pounds in 2016. The decrease compared to 2015 is the result of the restriction of mining activities at the end of 2015, which extended into 2016.

Tailings capacity

Under our current licence, we expect to have sufficient tailings capacity to support milling of Eagle Point ore until about late 2017, based upon expected ore tonnage, milling rates and tailings properties.

Our plan for fully utilizing the available tailings capacity of the Rabbit Lake In-Pit Tailings Management facility requires regulatory approval in 2016 for which we have submitted the required applications. With these regulatory approvals and after we complete the necessary work on the existing pit, we expect to then have sufficient tailings capacity to support milling of Eagle Point ore until at least 2021 based upon expected ore tonnage, milling rates, and tailings properties.

Exploration

We plan to continue our underground drilling reserve replacement program in areas of interest north and northeast of the current mine workings in 2016. The drilling will be carried out from underground locations.

Reclamation

As part of our multi-year site-wide reclamation plan, we spent over $0.7 million in 2015 to reclaim facilities that are no longer in use and plan to spend over $0.5 million in 2016.

FUEL SERVICES

2015 UPDATE

Production

Fuel services produced 9.7 million kgU, 16% lower than 2014. This was a result of our decision to decrease production in response to weak market conditions and the termination of our toll milling agreement with SFL in 2014.

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

The Vision in Motion project is currently in the feasibility stage and will continue with the CNSC licensing process in 2016, which is required to advance the project.

Labour relations

Approximately 100 unionized employees at Cameco Fuel Manufacturing Inc.’s operations in Port Hope and Cobourg, Ontario accepted a new collective bargaining agreement in the second quarter of 2015. The employees, represented by the United Steelworkers local 14193, agreed to a three-year contract that includes a 7% wage increase over the term of the agreement. The previous contract expired on June 1, 2015.

PLANNING FOR THE FUTURE AT FUEL SERVICES

Production

We have decreased our production target for 2016 to between 8 million and 9 million kgU in response to the continued weak market conditions.

Labour relations

The current collective bargaining agreement for our unionized employees at the Port Hope conversion facility expires on June 30, 2016. We will commence the bargaining process in early 2016.

 

- 20 -

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Regulatory

The current operating licence for the Port Hope conversion facility expires in February 2017. The CNSC relicensing process will take place in 2016.

Qualified persons

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

 

 

Caution about forward-looking information

This document 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 document as forward-looking information.

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

 

•

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 22, 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 21 and 22. 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 document

 

 

Material risks

 

 

- 21 -

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- 22 -

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Conference call

We invite you to join our fourth quarter conference call on Monday, February 8, 2016 at 11:00 a.m. Eastern.

The call will be open to all investors and the media. To join the call, please dial (800) 769-8320 (Canada and US) or (416) 340-8530. An operator will put your call through. A live audio feed of the conference call will be available from a link at cameco.com. See the link on our home page on the day of the call.

A recorded version of the proceedings will be available:

 

•

on our website, cameco.com, shortly after the call

 

•

on post view until midnight, Eastern, March 13, 2016, by calling (800) 408-3053 (Canada and US) or (905) 694-9451 (Passcode 5846753)

2016 quarterly report release dates

We plan to announce our 2016 quarter results as follows:

 

•

first quarter consolidated financial and operating results: before markets open on April 29, 2016

 

•

second quarter consolidated financial and operating results: before markets open on July 28, 2016

 

•

third quarter consolidated financial and operating results: before markets open on November 2, 2016

The 2017 date for the announcement of our fourth quarter and 2016 consolidated financial and operating results will be provided in our 2016 third quarter MD&A. Announcement dates are subject to change.

Additional information

Our 2015 annual management’s discussion and analysis, and annual audited financial statements, will be available shortly on our website at cameco.com, on SEDAR at sedar.com and on EDGAR at sec.gov/edgar.shtml. Our 2015 annual information form is expected to be available later in March.

Profile

We are one of the world’s largest uranium producers, a significant supplier of conversion services and one of two CANDU fuel manufacturers in Canada. Our competitive position is based on our controlling ownership of the world’s largest high-grade reserves and low-cost operations. Our uranium products are used to generate clean electricity in nuclear power plants around the world. We also explore for uranium in the Americas, Australia and Asia. Our shares trade on the Toronto and New York stock exchanges. Our head office is in Saskatoon, Saskatchewan.

As used in this news release, the terms we, us, our, the Company and Cameco mean Cameco Corporation and its subsidiaries; including NUKEM Energy GmbH, unless otherwise indicated.

- End -

 

Investor inquiries:		Rachelle Girard		(306) 956-6403
Media inquiries:		Gord Struthers		(306) 956-6593

 

- 23 -

Cameco Corporation

2015 consolidated financial statements

February 4, 2016

---

Report of management’s accountability

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

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

In addition, management is responsible for establishing and maintaining an adequate system of internal control over financial reporting. The internal control system includes an internal audit function and a code of conduct and ethics, which is communicated to all levels in the organization and requires all employees to maintain high standards in their conduct of the corporation’s affairs. Such systems are designed to provide reasonable assurance that the financial information is relevant, reliable and accurate and that the Company’s assets are appropriately accounted for and adequately safeguarded. Management conducted an evaluation of the effectiveness of the system of internal control over financial reporting based on the criteria established in “Internal Control – Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company’s system of internal control over financial reporting was effective as at December 31, 2015.

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

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

 

Original signed by Tim S. Gitzel		Original signed by Grant E. Isaac
President and Chief Executive Officer		Senior Vice-President and Chief Financial Officer
February 4, 2016		February 4, 2016

 

2

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Independent auditors’ report

To the Shareholders and Board of Directors of Cameco Corporation:

We have audited the accompanying consolidated financial statements of Cameco Corporation, which comprise the consolidated statements of financial position as at December 31, 2015 and December 31, 2014, the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s responsibility for the consolidated financial statements

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

Auditors’ responsibility

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

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

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

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Cameco Corporation as at December 31, 2015 and December 31, 2014 and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Board.

Original signed by KPMG LLP

Chartered Professional Accountants

February 4, 2016

Saskatoon, Canada

 

3

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Consolidated statements of earnings

 

For the years ended December 31		Note		2015				2014
($Cdn thousands, except per share amounts)
Revenue from products and services				$	2,754,378			$	2,397,532
Cost of products and services sold					1,744,815				1,420,768
Depreciation and amortization					312,518				338,983
Cost of sales					2,057,333				1,759,751
Gross profit					697,045				637,781
Administration					186,810				176,385
Impairment charges		9, 12			215,488				326,693
Exploration					40,259				46,565
Research and development					6,587				5,044
Loss on disposal of assets		9			2,326				44,762
Earnings from operations					245,575				38,332
Finance costs		20			(103,615	)			(111,853	)
Loss on derivatives		27			(280,610	)			(121,160	)
Finance income					5,417				7,402
Share of loss from equity-accounted investees		12			(758	)			(17,141	)
Other income		21			54,723				85,322
Loss before income taxes					(79,268	)			(119,098	)
Income tax recovery		22			(142,630	)			(175,268	)
Net earnings from continuing operations					63,362				56,170
Net earnings from discontinued operation		6			—				127,243
Net earnings				$	63,362			$	183,413
Equity holders					65,286				185,234
Non-controlling interest					(1,924	)			(1,821	)
Net earnings				$	63,362			$	183,413
Continuing operations					0.16				0.15
Discontinued operation					—				0.32
Total basic earnings per share		23		$	0.16			$	0.47
Continuing operations					0.16				0.15
Discontinued operation					—				0.32
Total diluted earnings per share		23		$	0.16			$	0.47

See accompanying notes to consolidated financial statements.

 

4

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Consolidated statements of comprehensive income

 

For the years ended December 31		Note		2015				2014
($Cdn thousands)
Net earnings				$	63,362			$	183,413
Other comprehensive income (loss), net of taxes:		22
Items that will not be reclassified to net earnings:
Remeasurements of defined benefit liability					2,015				(7,952	)
Items that are or may be reclassified to net earnings:
Exchange differences on translation of foreign operations					182,089				58,890
Gains on derivatives designated as cash flow hedges transferred to net earnings - discontinued operation					—				(300	)
Unrealized gains on available-for-sale assets					22				(613	)
Losses on available-for-sale assets transferred to earnings					—				2
Other comprehensive income, net of taxes					184,126				50,027
Total comprehensive income				$	247,488			$	233,440
Comprehensive income from continuing operations					247,488				106,497
Comprehensive income from discontinued operation		6			—				126,943
Total comprehensive income				$	247,488			$	233,440
Other comprehensive income (loss) attributable to:
Equity holders				$	184,288			$	49,969
Non-controlling interest					(162	)			58
Other comprehensive income for the year				$	184,126			$	50,027
Total comprehensive income (loss) attributable to:
Equity holders				$	249,574			$	235,203
Non-controlling interest					(2,086	)			(1,763	)
Total comprehensive income for the year				$	247,488			$	233,440

See accompanying notes to consolidated financial statements.

 

5

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Consolidated statements of financial position

 

As at December 31		Note		2015				2014
($Cdn thousands)
Assets
Current assets
Cash and cash equivalents				$	458,604			$	566,583
Accounts receivable		7			246,865				455,002
Current tax assets					493				3,096
Inventories		8			1,285,266				902,278
Supplies and prepaid expenses					180,544				130,406
Current portion of long-term receivables, investments and other		11			12,193				10,341
Total current assets					2,183,965				2,067,706
Property, plant and equipment		9			5,228,160				5,291,021
Goodwill and intangible assets		10			217,130				201,102
Long-term receivables, investments and other		11			449,236				423,280
Investments in equity-accounted investees		12			2,472				3,230
Deferred tax assets		22			713,674				486,328
Total non-current assets					6,610,672				6,404,961
Total assets				$	8,794,637			$	8,472,667
Liabilities and shareholders’ equity
Current liabilities
Accounts payable and accrued liabilities		13		$	317,856			$	316,258
Current tax liabilities					56,494				51,719
Dividends payable					39,579				39,579
Current portion of other liabilities		16			241,113				87,883
Current portion of provisions		17			16,595				20,375
Total current liabilities					671,637				515,814
Long-term debt		15			1,492,237				1,491,198
Other liabilities		16			132,142				172,034
Provisions		17			918,163				825,935
Deferred tax liabilities		22			35,179				23,882
Total non-current liabilities					2,577,721				2,513,049
Shareholders’ equity
Share capital					1,862,646				1,862,646
Contributed surplus					209,115				196,815
Retained earnings					3,241,902				3,333,099
Other components of equity					233,357				51,084
Total shareholders’ equity attributable to equity holders					5,547,020				5,443,644
Non-controlling interest					(1,741	)			160
Total shareholders’ equity					5,545,279				5,443,804
Total liabilities and shareholders’ equity				$	8,794,637			$	8,472,667

Commitments and contingencies [notes 9, 17, 22]

See accompanying notes to consolidated financial statements.

 

6

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Consolidated statements of changes in equity

 

		Attributable to equity holders
($Cdn thousands)		Share capital				Contributed surplus				Retained earnings				Foreign currency translation				Cash flow hedges				Available- for-sale assets				Total				Non- controlling interest				Total equity
Balance at January 1, 2015		$	1,862,646			$	196,815			$	3,333,099			$	51,667			$	—			$	(583	)		$	5,443,644			$	160			$	5,443,804
Net earnings (loss)			—				—				65,286				—				—				—				65,286				(1,924	)			63,362
Other comprehensive income (loss)			—				—				2,015				182,251				—				22				184,288				(162	)			184,126
Total comprehensive income (loss)			—				—				67,301				182,251				—				22				249,574				(2,086	)			247,488
Share-based compensation			—				16,853				—				—				—				—				16,853				—				16,853
Share options exercised			—				(4,553	)			—				—				—				—				(4,553	)			—				(4,553	)
Change in ownership interest in subsidiary			—				—				(185	)			—				—				—				(185	)			185				—
Dividends			—				—				(158,313	)			—				—				—				(158,313	)			—				(158,313	)
Balance at December 31, 2015		$	1,862,646			$	209,115			$	3,241,902			$	233,918			$	—			$	(561	)		$	5,547,020			$	(1,741	)		$	5,545,279
Balance at January 1, 2014		$	1,854,671			$	186,382			$	3,314,049			$	(7,165	)		$	300			$	28			$	5,348,265			$	1,129			$	5,349,394
Net earnings (loss)			—				—				185,234				—				—				—				185,234				(1,821	)			183,413
Other comprehensive income (loss)			—				—				(7,952	)			58,832				(300	)			(611	)			49,969				58				50,027
Total comprehensive income (loss)			—				—				177,282				58,832				(300	)			(611	)			235,203				(1,763	)			233,440
Share-based compensation			—				15,808				—				—				—				—				15,808				—				15,808
Share options exercised			7,975				(5,375	)			—				—				—				—				2,600				—				2,600
Dividends			—				—				(158,232	)			—				—				—				(158,232	)			—				(158,232	)
Transactions with owners - contributed equity			—				—				—				—				—				—				—				794				794
Balance at December 31, 2014		$	1,862,646			$	196,815			$	3,333,099			$	51,667			$	—			$	(583	)		$	5,443,644			$	160			$	5,443,804

See accompanying notes to consolidated financial statements.

 

7

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Consolidated statements of cash flows

 

For the years ended December 31 ($Cdn thousands)		Note		2015				2014
Operating activities
Net earnings				$	63,362			$	183,413
Adjustments for:
Depreciation and amortization					312,518				338,983
Deferred charges					5,834				61,869
Unrealized loss on derivatives					92,166				40,569
Share-based compensation		25			16,853				15,808
Loss on sale of assets					2,326				44,762
Finance costs		20			103,615				111,853
Finance income					(5,417	)			(7,402	)
Share of loss in equity-accounted investees					758				17,141
Impairment charge		9, 12			215,488				326,693
Other income		21			(54,409	)			(35,353	)
Discontinued operation		6			—				(127,243	)
Income tax recovery		22			(142,630	)			(175,268	)
Interest received					3,922				5,935
Income taxes paid					(92,758	)			(233,716	)
Other operating items		24			(71,618	)			(87,862	)
Net cash provided by operations					450,010				480,182
Investing activities
Additions to property, plant and equipment					(358,562	)			(480,108	)
Increase in long-term receivables, investments and other					17,557				11,569
Proceeds from sale of property, plant and equipment					198				701
Net cash used in investing (continuing operations)					(340,807	)			(467,838	)
Net cash provided by investing (discontinued operation)		6			—				447,096
Net cash used in investing					(340,807	)			(20,742	)
Financing activities
Increase in debt					—				496,476
Decrease in debt					(10	)			(351,046	)
Interest paid					(69,507	)			(78,144	)
Proceeds from issuance of shares, stock option plan					—				6,228
Contributions from non-controlling interest					—				794
Dividends paid					(158,313	)			(158,200	)
Net cash used in financing					(227,830	)			(83,892	)
Increase (decrease) in cash and cash equivalents, during the year					(118,627	)			375,548
Exchange rate changes on foreign currency cash balances					10,648				3,126
Cash and cash equivalents, beginning of year					566,583				187,909
Cash and cash equivalents, end of year				$	458,604			$	566,583
Cash and cash equivalents is comprised of:
Cash				$	240,603			$	86,664
Cash equivalents					218,001				479,919
Cash and cash equivalents				$	458,604			$	566,583

See accompanying notes to consolidated financial statements.

 

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Notes to consolidated financial statements

For the years ended December 31, 2015 and 2014

 

1.	Cameco Corporation

Cameco Corporation is incorporated under the Canada Business Corporations Act. The address of its registered office is 2121 11th Street West, Saskatoon, Saskatchewan, S7M 1J3. The consolidated financial statements as at and for the year ended December 31, 2015 comprise Cameco Corporation and its subsidiaries (collectively, the Company or Cameco) and the Company’s interests in associates and joint arrangements. The Company is primarily engaged in the exploration for and the development, mining, refining, conversion, fabrication and trading of uranium for sale as fuel for generating electricity in nuclear power reactors in Canada and other countries.

 

2.	Significant accounting policies

 

A.	Statement of compliance

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

These consolidated financial statements were authorized for issuance by the Company’s board of directors on February 4, 2016.

 

B.	Basis of presentation

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

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

 

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

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

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

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

 

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C.	Consolidation principles

 

i.	Business combinations

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

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

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

Acquisition-related costs are expensed as incurred, except for those costs related to the issue of debt or equity instruments.

 

ii.	Subsidiaries

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

 

iii.	Investments in equity-accounted investees

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

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

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

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

 

iv.	Joint arrangements

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

 

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

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

 

v.	Transactions eliminated on consolidation

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

 

D.	Foreign currency translation

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

 

i.	Foreign currency transactions

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

 

ii.	Foreign operations

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

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

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

 

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E.	Cash and cash equivalents

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

 

F.	Short-term investments

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

 

G.	Inventories

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

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

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

 

H.	Property, plant and equipment

 

i.	Buildings, plant and equipment and other

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

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

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

 

ii.	Mineral properties and mine development costs

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

The production stage is reached when a mine property is in the condition necessary for it to be capable of operating in the manner intended by management. The criteria used to assess the start date of the production stage are determined based on the nature of each mine construction project, including the complexity of a mine site. A range of factors is considered when determining whether the production stage has been reached, which includes, but is not limited to, the demonstration of sustainable production at or near the level intended (such as the demonstration of continuous throughput levels at or above a target percentage of the design capacity).

 

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iii.	Depreciation

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

 

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

Mining properties and certain mining and conversion assets for which the economic benefits from the asset are consumed in a pattern which is linked to the production level are depreciated according to the unit-of-production method. For conversion assets, the amount of depreciation is measured by the portion of the facilities’ total estimated lifetime production that is produced in that period. For mining assets and properties, the amount of depreciation or depletion is measured by the portion of the mines’ proven and probable mineral reserves recovered during the period.

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

 

iv.	Borrowing costs

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

 

v.	Repairs and maintenance

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

 

I.	Goodwill and intangible assets

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

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

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

 

J.	Leased assets

Leases which result in the Company receiving substantially all the risks and rewards of ownership are classified as finance leases. Upon initial recognition, the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments. Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset. Minimum lease payments made under finance leases are apportioned between finance cost and the reduction of the outstanding liability. The finance cost is allocated to each period of the lease term to produce a constant periodic rate of interest on the remaining balance of the liability.

 

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Lease agreements that do not meet the recognition criteria of a finance lease are classified and recognized as operating leases and are not recognized in the Company’s consolidated statements of financial position. Payments made under operating leases are charged to income on a straight-line basis over the lease term.

 

K.	Finance income and finance costs

Finance income comprises interest income on funds invested, gains on the disposal of available-for-sale financial assets, and changes in the fair value of non-derivative financial instruments. Interest income and interest expense are recognized in earnings as they accrue, using the effective interest method. Finance costs comprise interest and fees on borrowings, unwinding of the discount on provisions, changes in the fair value of non-derivative financial instruments and costs incurred on redemption of debentures.

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

 

L.	Research and development costs

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

 

M.	Impairment

 

i.	Non-derivative financial assets

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

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

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

 

ii.	Non-financial assets

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

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

 

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

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

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

 

N.	Exploration and evaluation expenditures

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

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

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

 

O.	Provisions

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

 

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i.	Environmental restoration

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

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

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

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

 

ii.	Waste disposal

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

 

P.	Employee future benefits

 

i.	Pension obligations

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

 

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

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

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

 

ii.	Other post-retirement benefit plans

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

 

iii.	Short-term employee benefits

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

 

iv.	Termination benefits

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

 

v.	Share-based compensation

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

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

 

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

 

Q.	Revenue recognition

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

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

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

Uranium supply

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

Toll conversion services

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

Conversion supply

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

 

R.	Financial instruments

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

 

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i.	Non-derivative financial assets and financial liabilities

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

Fair value through profit or loss

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

Held-to-maturity

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

Loans and receivables

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

Available-for-sale assets

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

Other financial liabilities

This category consists of all non-derivative financial liabilities that do not meet the definition of held-for-trading liabilities, and that have not been designated as liabilities at fair value through profit or loss. These liabilities are initially recognized at fair value less any directly attributable transaction costs and are subsequently measured at amortized cost using the effective interest method. Transaction costs arising on the issue of equity instruments are recognized directly in equity. Transaction costs that are directly related to the probable issuance of a security that is classified as a financial liability is deducted from the amount of the financial liability when it is initially recognized, or recognized in earnings when the issuance is no longer probable.

Cameco derecognizes a financial asset when the contractual rights to the cash flows from the asset expire, or it transfers the rights to receive the contractual cash flows in a transaction in which substantially all of the risks and rewards of ownership of the financial asset are transferred.

A financial liability is derecognized when its contractual obligations are discharged or cancelled, or expire.

 

ii.	Derivative financial instruments

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

The purpose of hedging transactions is to modify the Company’s exposure to one or more risks by creating an offset between changes in the fair value of, or the cash flows attributable to, the hedged item and the hedging item. When hedge accounting is appropriate, the hedging relationship is designated as a fair value hedge, a cash flow hedge, or a foreign currency risk hedge related to a net investment in a foreign operation. The Company does not have any instruments that have been designated as hedge transactions at December 31, 2015.

 

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Separable embedded derivatives

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

 

S.	Income tax

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

Current tax is the expected tax payable or receivable on the taxable income or loss for the year, using tax rates enacted or substantially enacted at the reporting date, and any adjustments to tax payable in respect of previous years. Current tax assets and liabilities are measured at the amount expected to be paid or recovered from the taxation authorities.

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

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

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

 

T.	Share capital

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

 

U.	Earnings per share

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

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

 

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V.	Segment reporting

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

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

 

W.	Discontinued operations

A discontinued operation is a component of the Company that has either been disposed of or that is classified as held for sale. A component of the Company is comprised of operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the Company. Net earnings of a discontinued operation and any gain or loss on disposal are combined and presented as net earnings from discontinued operations in the consolidated statements of earnings.

 

3.	Accounting standards

 

A.	New standards and interpretations not yet adopted

A number of new standards and amendments to existing standards are not yet effective for the year ended December 31, 2015, and have not been applied in preparing these consolidated financial statements. Cameco does not intend to early adopt any of the following amendments to existing standards and does not expect the amendments to have a material impact on the financial statements, unless otherwise noted.

 

i.

Revenue

In May 2014, the IASB issued IFRS 15, Revenue from Contracts with Customers (IFRS 15). IFRS 15 is effective for periods beginning on or after January 1, 2018 and is to be applied retrospectively. IFRS 15 clarifies the principles for recognizing revenue from contracts with customers. The extent of the impact of adoption of IFRS 15 has not yet been determined.

 

ii.	Financial instruments

In July 2014, the IASB issued IFRS 9, Financial Instruments (IFRS 9). IFRS 9 replaces the existing guidance in IAS 39, Financial Instruments: Recognition and Measurement (IAS 39). IFRS 9 includes revised guidance on the classification and measurement of financial assets, a new expected credit loss model for calculating impairment on financial assets and new hedge accounting requirements. It also carries forward, from IAS 39, guidance on recognition and derecognition of financial instruments.

IFRS 9 is effective for annual periods beginning on or after January 1, 2018, with early adoption of the new standard permitted. Cameco does not intend to early adopt IFRS 9. The extent of the impact of adoption of IFRS 9 has not yet been determined.

 

iii.

Leases

In January 2016, the IASB issued IFRS 16, Leases (IFRS 16). IFRS 16 is effective for periods beginning on or after January 1, 2019, with early adoption permitted. IFRS 16 eliminates the current dual model for lessees, which distinguishes between on-balance sheet finance leases and off-balance sheet operating leases. Instead, there is a single, on-balance sheet accounting model that is similar to current finance lease accounting. The extent of the impact of adoption of IFRS 16 has not yet been determined.

 

4.	Determination of fair values

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

 

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

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

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

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

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

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

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

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

Note 9 - Property, plant and equipment

Note 10 - Goodwill and intangible assets

Note 12 - Equity-accounted investees

Note 25 - Share-based compensation plans

Note 27 - Financial instruments and risk management

 

5.	Use of estimates and judgments

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

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

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

 

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A.	Recoverability of long-lived and intangible assets

Cameco assesses the carrying values of property, plant and equipment, and intangible assets when there is an indication of possible impairment. Goodwill and intangible assets not yet available for use or with indefinite useful lives are tested for impairment annually. If it is determined that carrying values of assets or goodwill cannot be recovered, the unrecoverable amounts are charged against current earnings. Recoverability is dependent upon assumptions and judgments regarding market conditions, costs of production, sustaining capital requirements and mineral reserves. Other assumptions used in the calculation of recoverable amounts are discount rates, future cash flows and profit margins. A material change in assumptions may significantly impact the potential impairment of these assets.

 

B.	Cash generating units

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

 

C.	Provisions for decommissioning and reclamation of assets

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

 

D.	Income taxes

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

 

E.	Commencement of production stage

Until a mining property is declared as being in the production stage, all costs related to its development are capitalized. The determination of the date on which a mine enters the production stage is a matter of judgment that impacts when capitalization of development costs ceases and depreciation of the mining property commences and is charged to earnings. Refer to note 2 (h)(ii) for further information on the criteria used to make this assessment.

 

F.	Mineral reserves

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

 

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G.	Purchase price allocations

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

 

H.	Determination of joint control

Cameco conducts certain operations through joint ownership interests. Judgment is required in assessing whether Cameco has joint control over the investee, which involves determining the relevant activities of the arrangement and whether decisions around relevant activities require unanimous consent. Judgment is also required to determine whether a joint arrangement should be classified as a joint venture or joint operation. Classifying the arrangement requires us to assess our rights and obligations arising from the arrangement. Specifically, management considers the structure of the joint arrangement and whether it is structured through a separate vehicle and when the arrangement is structured through a separate vehicle, we also consider the rights and obligations arising from the legal form of the separate vehicle, the terms of the contractual arrangements and other facts and circumstances, when relevant. This judgment influences whether we equity account or proportionately consolidate our interest in the arrangement.

 

6.	Discontinued operation

On March 27, 2014, Cameco completed the sale of its 31.6% limited partnership interest in Bruce Power L.P. (BPLP) which operates the four Bruce B nuclear reactors in Ontario. The aggregate sale price for Cameco’s interest in BPLP and certain related entities was $450,000,000. The sale has been accounted for effective January 1, 2014. Cameco received net proceeds of approximately $447,096,000 and realized an after tax gain of $127,243,000 on this divestiture.

As a result of the transaction, Cameco presented the results of BPLP as a discontinued operation and revised its statement of earnings, statement of comprehensive income and statement of cash flows to reflect this change in presentation. Net earnings from this discontinued operation are as follows:

 

		2015				2014
Share of earnings from BPLP and related entities		$	—			$	—
Tax expense			—				—
			—				—
Gain on disposal of BPLP and related entities			—				144,912
Tax expense on disposal			—				17,669
			—				127,243
Net earnings from discontinued operation		$	—			$	127,243

 

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7.	Accounts receivable

 

		2015				2014
Trade receivables		$	236,859			$	428,850
HST/VAT receivables			6,239				19,523
Other receivables			3,767				6,629
Total		$	246,865			$	455,002

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

 

8.	Inventories

 

		2015				2014
Uranium
Concentrate		$	887,083			$	500,342
Broken ore			41,722				21,289
			928,805				521,631
NUKEM			216,361				251,942
Fuel services			140,100				128,705
Total		$	1,285,266			$	902,278

In the second quarter of 2015, the production stage was reached at Cameco’s Cigar Lake operation. Effective May 1, 2015, we commenced charging all production costs, including depreciation, to inventory and subsequently recognizing in cost of sales as the product is sold.

Cameco expensed $1,935,000,000 of inventory as cost of sales during 2015 (2014 - $1,698,000,000). Included in cost of sales is a $3,400,000 net recovery, resulting from the reversal of previous NUKEM inventory write-downs to reflect net realizable value (2014 - $4,300,000).

NUKEM enters into financing arrangements where future receivables arising from certain sales contracts are sold to financial institutions in exchange for cash. These arrangements require NUKEM to satisfy its delivery obligations under the sales contracts, which are recognized as deferred sales (note 16). In addition, NUKEM is required to pledge the underlying inventory as security against these performance obligations. As of December 31, 2015, NUKEM had $97,945,000 ($70,770,000 (US)) of inventory pledged as security under financing arrangements ((2014 - $94,378,000 ($81,353,000 (US)).

 

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9.	Property, plant and equipment

At December 31, 2015

 

		Land and buildings				Plant and equipment				Furniture and fixtures				Under construction				Exploration and evaluation				Total
Cost
Beginning of year		$	3,423,736			$	1,984,721			$	120,072			$	1,962,500			$	1,084,715			$	8,575,744
Additions			35,579				23,919				1,329				292,443				2,450				355,720
Transfers			1,245,941				508,007				5,950				(1,747,248	)			(12,650	)			—
Change in reclamation provision			26,348				—				—				—				—				26,348
Disposals			(7,491	)			(38,077	)			(9,198	)			(2,476	)			(229	)			(57,471	)
Effect of movements in exchange rates			138,047				49,918				3,146				7,082				72,814				271,007
End of year			4,862,160				2,528,488				121,299				512,301				1,147,100				9,171,348
Accumulated depreciation and impairment
Beginning of year			1,769,526				1,164,969				104,101				91,621				154,506				3,284,723
Depreciation charge			232,179				133,655				12,925				—				192				378,951
Transfers			21,368				94				—				(21,462	)			—				—
Disposals			(2,296	)			(37,530	)			(9,168	)			—				—				(48,994	)
Impairment charge(a)			120,343				70,827				108				18,522				—				209,800
Effect of movements in exchange rates			85,082				21,293				2,478				—				9,855				118,708
End of year			2,226,202				1,353,308				110,444				88,681				164,553				3,943,188
Net book value at December 31, 2015		$	2,635,958			$	1,175,180			$	10,855			$	423,620			$	982,547			$	5,228,160

At December 31, 2014

 

		Land and buildings				Plant and equipment				Furniture and fixtures				Under construction				Exploration and evaluation				Total
Cost
Beginning of year		$	2,971,894			$	1,819,611			$	97,220			$	1,904,400			$	1,072,242			$	7,865,367
Additions			26,688				18,288				5,716				407,492				14,640				472,824
Transfers			143,639				152,564				17,171				(313,374	)			—				—
Change in reclamation provision			228,223				—				—				—				—				228,223
Disposals(c)			(902	)			(24,463	)			(1,111	)			(40,664	)			(10,984	)			(78,124	)
Effect of movements in exchange rates			54,194				18,721				1,076				4,646				8,817				87,454
End of year			3,423,736				1,984,721				120,072				1,962,500				1,084,715				8,575,744
Accumulated depreciation and impairment
Beginning of year			1,491,681				1,019,529				81,216				70,159				161,789				2,824,374
Depreciation charge			185,238				111,980				23,574				94				161				321,047
Transfers			(4,190	)			4,190				—				—				—				—
Disposals			(678	)			(16,736	)			(336	)			—				(7,160	)			(24,910	)
Impairment charge(b)			66,084				38,968				—				21,368				—				126,420
Effect of movements in exchange rates			31,391				7,038				(353	)			—				(284	)			37,792
End of year			1,769,526				1,164,969				104,101				91,621				154,506				3,284,723
Net book value at December 31, 2014		$	1,654,210			$	819,752			$	15,971			$	1,870,879			$	930,209			$	5,291,021

 

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Cameco has contractual capital commitments of approximately $55,000,000 at December 31, 2015. Certain of the contractual commitments may contain cancellation clauses, however the Company discloses the commitments based on management’s intent to fulfill the contract. The majority of this amount is expected to be incurred in 2016.

(a) During 2015, Cameco recognized a $209,800,000 impairment charge relating to its Rabbit Lake mill in northern Saskatchewan, which is part of its uranium segment. Due to increased uncertainty around future production sources for the Rabbit Lake mill as a result of ongoing economic conditions, the Company concluded it was appropriate to recognize an impairment charge. The amount of the charge was determined as the excess of the carrying value over the recoverable amount. The recoverable amount of the mill was determined to be $68,971,000 based on a fair value less costs to sell model, which incorporated the future cash flows expected to be derived from the mill. It is categorized as a non-recurring level 3 fair value measurement.

The discount rate used in the fair value less costs to sell calculation was 8% and was determined based on a market participant’s incremental borrowing cost, adjusted for the marginal return that the participant would expect to use on an investment in the mill. The recoverable amount is not sensitive to changes in the discount rate. Other key assumptions include operating and capital cost forecasts and the margin applied. Operating and capital cost forecasts have been determined based on management’s internal cost estimates. A 10% increase in these cost assumptions decreases the recoverable amount by $7,900,000.

(b) During 2014, Cameco recognized a $126,420,000 impairment charge relating to its Rabbit Lake mine in northern Saskatchewan, which is part of its uranium segment. Due to the deferral of various projects that were related to planned production over the remaining life of the Eagle Point mine, the Company concluded it was appropriate to recognize an impairment charge. The amount of the charge was determined as the excess of the carrying value over the recoverable amount. The recoverable amount of the mine was determined to be $28,570,000 based on a fair value less costs to sell model, which incorporated the future cash flows expected to be derived from the mine. It is categorized as a non-recurring level 3 fair value measurement.

The discount rate used in the fair value less costs to sell calculation was 8% and was determined based on a market participant’s incremental borrowing cost, adjusted for the marginal return that the participant would expect to use on an investment in the mine. The recoverable amount is not sensitive to changes in the discount rate. Other key assumptions include uranium price forecasts and operating and capital cost forecasts. Uranium prices applied in the calculation were based on approved internal price forecasts, which reflect management’s expectation of prices that a market participant would use. Operating and capital cost forecasts have been determined based on management’s internal cost estimates. A $1/lb decrease in the uranium price assumption decreases the recoverable amount by $17,600,000.

(c) Due to extended low market conditions and continued efforts to reduce costs, certain projects were re-evaluated. As a result, the Company wrote off $40,664,000 of assets under construction on these projects in 2014.

 

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10.	Goodwill and intangible assets

 

A.	Reconciliation of carrying amount

At December 31, 2015

 

		Goodwill				Contracts				Intellectual property				Patents				Total
Cost
Beginning of year		$	102,526			$	101,549			$	118,819			$	10,141			$	333,035
Effect of movements in exchange rates			19,788				19,599				—				1,957				41,344
End of year			122,314				121,148				118,819				12,098				374,379
Accumulated amortization
Beginning of year			—				88,978				40,992				1,963				131,933
Amortization charge			—				2,458				4,438				609				7,505
Effect of movements in exchange rates			—				17,373				—				438				17,811
End of year			—				108,809				45,430				3,010				157,249
Net book value at December 31, 2015		$	122,314			$	12,339			$	73,389			$	9,088			$	217,130

At December 31, 2014

		Goodwill				Contracts				Intellectual property				Patents				Total
Cost
Beginning of year		$	93,998			$	93,102			$	118,819			$	9,298			$	315,217
Effect of movements in exchange rates			8,528				8,447				—				843				17,818
End of year			102,526				101,549				118,819				10,141				333,035
Accumulated amortization
Beginning of year			—				82,960				36,940				1,286				121,186
Amortization charge			—				(1,438	)			4,052				531				3,145
Effect of movements in exchange rates			—				7,456				—				146				7,602
End of year			—				88,978				40,992				1,963				131,933
Net book value at December 31, 2014		$	102,526			$	12,571			$	77,827			$	8,178			$	201,102

 

B.	Amortization

The intangible asset values relate to intellectual property acquired with Cameco Fuel Manufacturing Inc. (CFM), patents acquired with UFP Investments LLC (UFP) and purchase and sales contracts acquired with NUKEM. The CFM intellectual property is being amortized on a unit-of-production basis over its remaining life. Amortization is allocated to the cost of inventory and is recognized in cost of products and services sold as inventory is sold. The patents acquired with UFP are being amortized to cost of products and services sold on a straight-line basis over their remaining life which expires in July 2029. The NUKEM purchase and sales contracts will be amortized to earnings over the remaining terms of the underlying contracts, which extend to 2022. Amortization of the purchase contracts is allocated to the cost of inventory and is included in cost of products and services sold as inventory is sold. Sales contracts are amortized to revenue. Approximately $3,517,000 of pre-tax earnings (in USD) relating to the amortization of the fair value allocated to the NUKEM contracts will be amortized in 2016 with the remaining balance being recognized fairly evenly each year through 2022.

 

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C.	Impairment test

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

The recoverable amount of NUKEM was estimated based on a value in use calculation, which involved discounting the future cash flows expected to be generated from the continuing use of the CGU. The estimated recoverable amount of NUKEM exceeded its carrying amount by approximately $55,524,000 (US) and therefore no impairment loss was recognized.

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

 

		2015
Discount rate (pre-tax)			11.8	%
Discount rate (post-tax)			8.8	%
Terminal value growth rate			2.5	%

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

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

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

 

		Change in assumption		Amount of decrease
Discount rate		1% increase		$	37,222
Terminal value growth rate		1% decrease			30,805
Uranium prices		$1/lb decrease			6,001
Perpetual annual cash flow		$1 million (US) decrease			11,131

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

 

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11.	Long-term receivables, investments and other

 

		2015				2014
Investments in equity securities [note 27]		$	938			$	6,601
Derivatives [note 27]			11,143				3,889
Advances receivable from JV Inkai LLP [note 32]			87,188				91,672
Investment tax credits			93,972				90,658
Amounts receivable related to tax dispute [note 22]			232,614				211,604
Other			35,574				29,197
			461,429				433,621
Less current portion			(12,193	)			(10,341	)
Net		$	449,236			$	423,280

 

12.	Equity-accounted investees

Associates

 

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

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

During 2014, a decision was made by the majority partner of GLE to significantly reduce funding of the project. Because the technology is unique to the industry and inherently risky, the significant reduction of funding introduced a further level of risk and jeopardized the viability of the project. As a result, Cameco determined the fair value less costs to sell to be nil and as such recognized an impairment charge of $183,615,000, which represented the full amount of Cameco’s investment. Future contributions to the project are being reflected in net earnings.

The following table summarizes the share of GLE’s earnings that Cameco has recognized:

 

		2015				2014
Loss from operations and comprehensive loss		$	—			$	(55,279	)
Cameco’s share of loss from operations and comprehensive loss (24%)		$	—			$	(13,267	)

Following the impairment of the investment in 2014, Cameco discontinued recognizing its share of losses in GLE. Cameco’s contributions to GLE are recorded in earnings as research and development.

 

ii.	Other associate

Cameco has one other associate. The following table summarizes the carrying amount and share of loss and other comprehensive income of this associate:

 

		2015				2014
Carrying amount of associate		$	2,472			$	3,230
Share of loss from operations and comprehensive loss		$	(758	)		$	(3,874	)

At December 31, 2015, the quoted value of the Company’s share in this associate that has shares listed on a recognized stock exchange was $7,503,000 (2014 - $14,256,000).

 

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13.	Accounts payable and accrued liabilities

 

		2015				2014
Trade payables		$	199,084			$	183,120
Non-trade payables			107,731				114,174
Payables due to related parties			11,041				18,964
Total		$	317,856			$	316,258

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

 

14.	Short-term debt

Cameco borrows directly in the commercial paper market. At December 31, 2015 and 2014, there was no commercial paper outstanding.

NUKEM has a multicurrency revolving loan facility that is available until October 1, 2020. Total funds of €75,000,000 are available under the facility, with the option to increase the facility by an additional €25,000,000. Amounts can be drawn in either Euros or US dollars in the form of bank overdrafts, letters of credit, short-term loans or foreign exchange facilities. Any amounts drawn in Euros bear interest at a rate equal to the comparable EURIBOR on the draw date plus 0.6%, while amounts drawn in US dollars bear interest at a rate equal to the comparable LIBOR on the draw date plus 0.6%.

At December 31, 2015 and 2014, there were no amounts withdrawn against the facility. As of December 31, 2015, NUKEM has $406,000 (US) in letters of credit outstanding against the facility in support of performance obligations under outstanding delivery contracts (2014 - $356,000 (US)).

The terms of the facility contain a financial covenant that requires NUKEM to maintain a minimum working capital to debt ratio of 1.35. The facility also stipulates Cameco as a guarantor for NUKEM’s withdrawals and requires the Company to maintain a credit rating of at least BBB-. Failure to comply with these covenants could result in cancellation of the facility and accelerated payment of any outstanding amounts. As of December 31, 2015, NUKEM and Cameco were in compliance with the covenants and the Company does not expect its operating and investing activities in 2016 to be constrained by them.

 

15.	Long-term debt

 

		2015				2014
Unsecured debentures
Series D - 5.67% debentures due September 2, 2019		$	497,954			$	497,465
Series E - 3.75% debentures due November 14, 2022			398,097				397,857
Series F - 5.09% debentures due November 14, 2042			99,243				99,230
Series G - 4.19% debentures due June 24, 2024			496,943				496,646
Total		$	1,492,237			$	1,491,198

On June 24, 2014, Cameco issued $500,000,000 of Series G debentures and announced the early redemption of the outstanding Series C debentures. The Series G debentures bear interest at a rate of 4.19% per annum. The net proceeds of the issue after deducting expenses were approximately $496,400,000. The debentures mature on June 24, 2024 and are being amortized at an effective interest rate of 4.28%. The $300,000,000 principal amount of the Series C debentures was redeemed on July 16, 2014. The company incurred total charges of $12,135,000 in relation to the early redemption of these debentures (note 20).

 

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Cameco has a $1,250,000,000 unsecured revolving credit facility that is available until November 1, 2019. Upon mutual agreement, the facility can be extended for an additional year on the anniversary date. In addition to direct borrowings under the facility, up to $100,000,000 can be used for the issuance of letters of credit and, to the extent necessary, it may be used to provide liquidity support for the Company’s commercial paper program. The agreement also provides the ability to increase the revolving credit facility above $1,250,000,000 by increments no less than $50,000,000, to a total of $1,750,000,000. The facility ranks equally with all of Cameco’s other senior debt. As of December 31, 2015 and 2014, there were no amounts outstanding under this facility.

Cameco has $1,490,809,000 (2014 - $1,068,420,000) in letter of credit facilities. Outstanding and committed letters of credit at December 31, 2015 amounted to $1,384,061,000 (2014 - $950,716,000), the majority of which relate to future decommissioning and reclamation liabilities (note 17).

Cameco is bound by a covenant in its revolving credit facility. The covenant requires a funded debt to tangible net worth ratio equal to or less than 1:1. Non-compliance with this covenant could result in accelerated payment and termination of the revolving credit facility. At December 31, 2015, Cameco was in compliance with the covenant and does not expect its operating and investing activities in 2016 to be constrained by it.

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

 

2016		2017				2018				2019				2020				Thereafter				Total
$—			—				—				497,954				—				994,283			$	1,492,237

 

16.	Other liabilities

 

		2015				2014
Deferred sales		$	132,904			$	123,298
Derivatives [note 27]			168,236				67,916
Accrued pension and post-retirement benefit liability [note 26]			64,135				61,670
Other			7,980				7,033
			373,255				259,917
Less current portion			(241,113	)			(87,883	)
Net		$	132,142			$	172,034

Deferred sales includes $110,749,000 ($80,021,000 (US)) of performance obligations relating to financing arrangements entered into by NUKEM (2014 - $107,076,000 ($92,299,000 (US))) (note 8).

 

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17.	Provisions

 

		Reclamation				Waste disposal				Total
Beginning of year		$	828,015			$	18,295			$	846,310
Changes in estimates and discount rates			26,348				58				26,406
Provisions used during the period			(10,848	)			(959	)			(11,807	)
Unwinding of discount			21,098				330				21,428
Effect of movements in exchange rates			52,421				—				52,421
End of period		$	917,034			$	17,724			$	934,758
Current		$	12,994			$	3,601			$	16,595
Non-current			904,040				14,123				918,163
		$	917,034			$	17,724			$	934,758

 

A.	Reclamation provision

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

Cameco estimates total future decommissioning and reclamation costs for its existing operating assets to be $974,785,000 (2014 - $874,314,000). The expected timing of these outflows is based on life-of-mine plans with the majority of expenditures expected to occur after 2021. These estimates are reviewed by Cameco technical personnel as required by regulatory agencies or more frequently as circumstances warrant. In connection with future decommissioning and reclamation costs, Cameco has provided financial assurances of $1,010,784,000 (2014 - $910,902,000) in the form of letters of credit to satisfy current regulatory requirements.

The reclamation provision relates to the following segments:

 

		2015				2014
Uranium		$	741,561			$	682,769
Fuel services			175,473				145,246
Total		$	917,034			$	828,015

 

B.	Waste disposal

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

Cameco estimates total future costs related to existing waste disposal to be $17,158,000 (2014 - $18,100,000). These outflows are expected to occur within the next three years.

 

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18.	Share capital

Authorized share capital:

 

•

Unlimited number of first preferred shares

 

•

Unlimited number of second preferred shares

 

•

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

 

•

One Class B share

 

A.	Common Shares

 

Number issued (number of shares)		2015				2014
Beginning of year			395,792,522				395,477,230
Issued:
Stock option plan [note 25]			—				315,292
Total			395,792,522				395,792,522

All issued shares are fully paid.

 

B.	Class B share

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

 

C.

Dividends

Dividends on Cameco Corporation common shares are declared in Canadian dollars. For the year ended December 31, 2015, the dividend declared per share was $0.40 (December 31, 2014 - $0.40).

 

19.	Employee benefit expense

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

 

		2015				2014
Wages and salaries		$	397,730			$	353,254
Statutory and company benefits			65,936				66,456
Equity-settled share-based compensation [note 25]			22,148				21,048
Expenses related to defined benefit plans [note 26]			5,003				7,605
Contributions to defined contribution plans [note 26]			17,961				17,274
Cash-settled share-based compensation [note 25]			(1,011	)			(1,616	)
Total		$	507,767			$	464,021

 

20.	Finance costs

 

		2015				2014
Interest on long-term debt		$	74,969			$	67,614
Unwinding of discount on provisions			21,428				20,671
Other charges			7,101				6,531
Loss on redemption of Series C debentures [note 15]			—				12,135
Interest on short-term debt			117				4,902
Total		$	103,615			$	111,853

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

 

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21.	Other income (expense)

 

		2015				2014
Foreign exchange gains		$	59,323			$	34,731
Contract settlement			—				65,557
Contract termination fee			—				(18,304	)
Other			(4,600	)			3,338
Total		$	54,723			$	85,322

In 2014, Cameco recorded an early termination fee of $18,304,000, incurred as a result of the cancellation of our toll conversion agreement with Springfields Fuels Ltd., which was to expire in 2016.

In addition, Cameco recorded a gain with respect to a long-term supply contract with one of its utility customers. The $65,557,000 reflected as income from contract settlement related to deliveries that the customer refused to take in the years 2012 through 2017. This represented the full amount to be received in relation to this contract dispute.

 

22.	Income taxes

 

A.	Significant components of deferred tax assets and liabilities

 

		Recognized in earnings								As at December 31
		2015				2014				2015				2014
Assets
Provision for reclamation		$	1,572			$	75,732			$	253,821			$	251,045
Foreign exploration and development			(782	)			(807	)			5,322				6,103
Income tax losses			88,186				136,294				424,344				335,856
Defined benefit plan actuarial losses			—				—				5,184				5,813
Long-term investments and other			15,316				1,424				82,273				67,060
Deferred tax assets			104,292				212,643				770,944				665,877
Liabilities
Property, plant and equipment			(111,080	)			(1,334	)			69,875				182,841
Inventories			1,984				(15,719	)			22,574				20,590
Other			—				(3,102	)			—				—
Deferred tax liabilities			(109,096	)			(20,155	)			92,449				203,431
Net deferred tax asset		$	213,388			$	232,798			$	678,495			$	462,446

 

		2015				2014
Deferred tax allocated as
Deferred tax assets		$	713,674			$	486,328
Deferred tax liabilities			(35,179	)			(23,882	)
Net deferred tax asset		$	678,495			$	462,446

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

 

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B.	Movement in net deferred tax assets and liabilities

 

		2015				2014
Net deferred tax asset at beginning of year		$	462,446			$	224,294
Recovery for the year in net earnings(a)			213,388				246,558
Expense on discontinued operations			—				(13,761	)
Recovery (expense) for the year in comprehensive income			(669	)			3,171
Effect of movements in exchange rates			3,330				2,184
End of year		$	678,495			$	462,446

 

(a)	During the fourth quarter, we reversed amounts related to our deferred tax asset in the US totalling $72,600,000. We determined that it was no longer probable that there would be sufficient taxable profit in the future against which the operating losses and other tax deductions could be used.

 

C.	Significant components of unrecognized deferred tax assets

 

		2015				2014
Income tax losses		$	194,045			$	130,300
Property, plant and equipment			1,904				1,404
Provision for reclamation			25,952				—
Long-term investments and other			107,305				85,927
Total		$	329,206			$	217,631

 

D.	Tax rate reconciliation

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

 

		2015				2014
Loss from continuing operations before income taxes and non-controlling interest		$	(79,268	)		$	(119,098	)
Combined federal and provincial tax rate			26.9	%			26.9	%
Computed income tax recovery			(21,323	)			(32,037	)
Increase (decrease) in taxes resulting from:
Difference between Canadian rates and rates applicable to subsidiaries in other countries			(197,967	)			(225,368	)
Change in unrecognized deferred tax assets			111,575				76,009
Other taxes			2,172				3,430
Share-based compensation plans			1,528				2,094
Change in tax provision related to transfer pricing			(35,000	)			12,000
Non-deductible (non-taxable) capital amounts			(2,362	)			(8,108	)
Other permanent differences			(1,253	)			(3,288	)
Income tax recovery		$	(142,630	)		$	(175,268	)

 

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E.	Earnings and income taxes by jurisdiction

 

		2015				2014
Earnings (loss) from continuing operations before income taxes
Canada		$	(959,661	)		$	(840,705	)
Foreign			880,393				721,607
		$	(79,268	)		$	(119,098	)
Current income taxes (recovery)
Canada		$	14,617			$	(2,944	)
Foreign			56,141				74,234
		$	70,758			$	71,290
Deferred income taxes (recovery)
Canada		$	(291,363	)		$	(209,255	)
Foreign			77,975				(37,303	)
		$	(213,388	)		$	(246,558	)
Income tax recovery		$	(142,630	)		$	(175,268	)

 

F.	Reassessments

Canada

In 2008, as part of the ongoing annual audits of Cameco’s Canadian tax returns, Canada Revenue Agency (CRA) disputed the transfer pricing structure and methodology used by Cameco and its wholly owned Swiss subsidiary, Cameco Europe Ltd., in respect of sale and purchase agreements for uranium products. From December 2008 to date, CRA issued notices of reassessment for the taxation years 2003 through 2010, which in aggregate have increased Cameco’s income for Canadian tax purposes by approximately $3,400,000,000. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229,000,000. Cameco believes it is likely that CRA will reassess Cameco’s tax returns for subsequent years on a similar basis and that these will require Cameco to make future remittances or provide security on receipt of the reassessments.

Using the methodology we believe that CRA will continue to apply and including the $3,400,000,000 already reassessed, we expect to receive notices of reassessment for a total of approximately $7,000,000,000 for the years 2003 through 2015, which would increase Cameco’s income for Canadian tax purposes and result in a related tax expense of approximately $2,100,000,000. In addition to penalties already imposed, CRA may continue to apply penalties to taxation years subsequent to 2009. As a result, we estimate that cash taxes and transfer pricing penalties would be between $1,650,000,000 and $1,700,000,000. In addition, we estimate there would be interest and instalment penalties applied that would be material to Cameco. While in dispute, we would be responsible for remitting or otherwise securing 50% of the cash taxes and transfer pricing penalties (between $825,000,000 and $850,000,000), plus related interest and instalment penalties assessed, which would be material to Cameco.

Under Canadian federal and provincial tax rules, the amount required to be remitted each year will depend on the amount of income reassessed in that year and the availability of elective deductions. Recently, the CRA disallowed the use of any loss carry-backs to be applied to any transfer pricing adjustment, starting with the 2008 tax year. In light of our view of the likely outcome of the case, we expect to recover the amounts remitted to CRA, including cash taxes, interest and penalties totalling $232,614,000 already paid as at December 31, 2015 (December 31, 2014 - $211,604,000) (note 11). In addition to the cash remitted, we have provided $332,000,000 in letters of credit to secure 50% of the cash taxes and related interest amounts reassessed in 2015.

 

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The case on the 2003, 2005 and 2006 reassessments is expected to go to trial in the third quarter of 2016. If this timing is adhered to, we expect to have a Tax Court decision within six to 18 months after the trial is complete.

Having regard to advice from its external advisors, Cameco’s opinion is that CRA’s position is incorrect and Cameco is contesting CRA’s position and expects to recover any amounts remitted or secured as a result of the reassessments. However, to reflect the uncertainties of CRA’s appeals process and litigation, Cameco has recorded a cumulative tax provision related to this matter for the years 2003 through the current period in the amount of $50,000,000 (previously $92,000,000). We have reduced the provision to reflect management’s revised estimate which takes into account additional contract information. While the resolution of this matter may result in liabilities that are higher or lower than the reserve, management believes that the ultimate resolution will not be material to Cameco’s financial position, results of operations or liquidity in the year(s) of resolution. Resolution of this matter as stipulated by CRA would be material to Cameco’s financial position, results of operations or liquidity in the year(s) of resolution and other unfavourable outcomes for the years 2003 to date could be material to Cameco’s financial position, results of operations and cash flows in the year(s) of resolution.

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

United States

In 2015, we received Revenue Agent’s Reports (RARs) from the Internal Revenue Service (IRS) pertaining to the taxation years 2009, 2010 and 2011-2012, challenging the transfer pricing used under certain intercompany transactions. The RARs list the IRS’ proposed adjustments to taxable income and calculate the tax and penalties owing based on the proposed adjustments.

The proposed adjustments reflected in the RARs are focused on transfer pricing in respect of certain intercompany transactions within our corporate structure. The IRS asserts that a portion of the non-US income reported under our corporate structure and taxed outside the US should be recognized and taxed in the US. Having regard to advice from its external advisors, management believes that the conclusions of the IRS in the RARs are incorrect and is contesting them in an administrative appeal of the proposed adjustments. No cash payments are required while pursuing an administrative appeal. Management believes that the ultimate resolution of this matter will not be material to our financial position, results of operations or liquidity in the year(s) of resolution.

 

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G.	Income tax losses

At December 31, 2015, income tax losses carried forward of $2,177,332,000 (2014 - $1,632,194,000) are available to reduce taxable income. These losses expire as follows:

 

Date of expiry		Canada				US				Other				Total
2020		$	—			$	—			$	1,247			$	1,247
2028			94,702				—				—				94,702
2029			—				28,440				—				28,440
2030			—				1,661				—				1,661
2031			100,872				24,256				—				125,128
2032			234,093				23,938				—				258,031
2033			273,689				40,808				—				314,497
2034			280,382				22,511				—				302,893
2035			305,950				55,939				—				361,889
2036			—				—				—				—
2037			—				—				—				—
2038			—				—				—				—
2039			—				—				—				—
No expiry			—				—				688,844				688,844
		$	1,289,688			$	197,553			$	690,091			$	2,177,332

Included in the table above is $615,412,000 (2014 - $434,051,000) of temporary differences related to loss carry forwards where no future benefit is realized.

 

H.	Other comprehensive income

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

For the year ended December 31, 2015

 

		Before tax				Income tax expense				Net of tax
Remeasurements of defined benefit liability		$	2,681			$	(666	)		$	2,015
Exchange differences on translation of foreign operations			182,089				—				182,089
Unrealized gains on available-for-sale assets			25				(3	)			22
		$	184,795			$	(669	)		$	184,126

 

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For the year ended December 31, 2014

 

		Before tax				Income tax recovery (expense)				Net of tax
Remeasurements of defined benefit liability		$	(10,930	)		$	2,978			$	(7,952	)
Exchange differences on translation of foreign operations			58,890				—				58,890
Gains on derivatives designated as cash flow hedges transferred to net earnings - discontinued operation			(400	)			100				(300	)
Unrealized losses on available-for-sale assets			(707	)			94				(613	)
Losses on available-for-sale assets transferred to net earnings			3				(1	)			2
		$	46,856			$	3,171			$	50,027

 

23.	Per share amounts

Per share amounts have been calculated based on the weighted average number of common shares outstanding during the period. The weighted average number of paid shares outstanding in 2015 was 395,792,522 (2014 - 395,740,117).

 

		2015				2014
Basic earnings per share computation
Net earnings attributable to equity holders		$	65,286			$	185,234
Weighted average common shares outstanding			395,793				395,740
Basic earnings per common share		$	0.16			$	0.47
Diluted earnings per share computation
Net earnings attributable to equity holders		$	65,286			$	185,234
Weighted average common shares outstanding			395,793				395,740
Dilutive effect of stock options			—				315
Weighted average common shares outstanding, assuming dilution			395,793				396,055
Diluted earnings per common share		$	0.16			$	0.47

 

24.	Statements of cash flows

 

		2015				2014
Changes in non-cash working capital:
Accounts receivable		$	216,266			$	(18,063	)
Inventories			(238,549	)			12,690
Supplies and prepaid expenses			(46,620	)			50,522
Accounts payable and accrued liabilities			(12,225	)			(141,905	)
Reclamation payments			(11,807	)			(15,425	)
Amortization of purchase price allocation			16,005				23,339
Other			5,312				980
Other operating items		$	(71,618	)		$	(87,862	)

 

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25.	Share-based compensation plans

The Company has the following equity-settled plans:

 

A.	Stock option plan

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

The aggregate number of common shares that may be issued pursuant to the Cameco stock option plan shall not exceed 43,017,198 of which 27,870,079 shares have been issued.

Stock option transactions for the respective years were as follows:

 

(Number of options)		2015				2014
Beginning of year			8,353,006				9,817,443
Options granted			965,823				765,146
Options forfeited			(297,461	)			(218,102	)
Options expired			(518,130	)			(1,696,189	)
Options exercised [note 18]			—				(315,292	)
End of year			8,503,238				8,353,006
Exercisable			6,475,811				5,819,252

Weighted average exercise prices were as follows:

 

		2015				2014
Beginning of year		$	28.22			$	29.95
Options granted			19.30				26.81
Options forfeited			29.60				30.69
Options expired			46.48				38.93
Options exercised			—				19.75
End of year		$	26.04			$	28.22
Exercisable		$	27.34			$	30.39

Total options outstanding and exercisable at December 31, 2015 were as follows:

 

								Options outstanding								Options exercisable
Option price per share				Number				Weighted average remaining life				Weighted average exercisable price				Number				Weighted average exercisable price
$	19.30 - 34.99				6,761,748				4.6			$	22.63				4,734,321			$	22.94
$	35.00 - 54.38				1,741,490				2.1			$	39.29				1,741,490			$	39.29
					8,503,238												6,475,811

The foregoing options have expiry dates ranging from March 3, 2016 to March 1, 2023.

 

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

 

(Number of options)		2015				2014
Beginning of year			2,533,754				3,537,814
Options granted			965,823				765,146
Options forfeited			(17,320	)			(58,686	)
Options vested			(1,454,830	)			(1,710,520	)
End of year			2,027,427				2,533,754

 

B.	Executive performance share unit (PSU)

The Company has established a PSU plan whereby it provides each plan participant an annual grant of PSUs in an amount determined by the board. Each PSU represents one phantom common share that entitles the participant to a payment of one Cameco common share purchased on the open market, or cash at the board’s discretion, at the end of each three-year period if certain performance and vesting criteria have been met. The final value of the PSUs will be based on the value of Cameco common shares at the end of the three-year period and the number of PSUs that ultimately vest. Vesting of PSUs at the end of the three-year period will be based on total shareholder return over the three years, Cameco’s ability to meet its annual operating targets and whether the participating executive remains employed by Cameco at the end of the three-year vesting period. As of December 31, 2015, the total number of PSUs held by the participants, after adjusting for forfeitures on retirement, was 791,071 (2014 - 620,654).

 

C.	Restricted share unit (RSU)

In 2011, the Company established an RSU plan whereby it provides each plan participant an annual grant of RSUs in an amount determined by the board. In 2014, Cameco expanded the scope of the RSU plan to include additional employees of the Company. Each RSU represents one phantom common share that entitles the participant to a payment of one Cameco common share purchased on the open market, or cash, at the board’s discretion. The RSUs carry vesting periods of one to three years, and the final value of the units will be based on the value of Cameco common shares at the end of the vesting periods. As of December 31, 2015, the total number of RSUs held by the participants was 479,320 (2014 - 246,394).

 

D.	Employee share ownership plan

Cameco also has an employee share ownership plan, whereby both employee and Company contributions are used to purchase shares on the open market for employees. The Company’s contributions are expensed during the year of contribution. Under the plan, employees have the opportunity to participate in the program to a maximum of 6% of eligible earnings each year with Cameco matching the first 3% of employee-paid shares by 50%. Cameco contributes $1,000 of shares annually to each employee that is enrolled in the plan. Shares purchased with Company contributions and with dividends paid on such shares become unrestricted 12 months from the date on which such shares were purchased. At December 31, 2015, there were 3,659 participants in the plan (2014 - 3,704). The total number of shares purchased in 2015 with Company contributions was 309,251 (2014 - 280,765). In 2015, the Company’s contributions totalled $5,295,000 (2014 - $5,240,000).

 

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

 

		2015				2014
Stock option plan		$	5,610			$	7,802
Performance share unit plan			6,574				5,199
Restricted share unit plan			4,669				2,807
Employee share ownership plan			5,295				5,240
End of year		$	22,148			$	21,048

Fair value measurement of equity-settled plans

The fair value of the units granted through the PSU plan was determined based on Monte Carlo simulation and the fair value of options granted under the stock option plan was measured based on the Black-Scholes option-pricing model. The fair value of RSUs granted was determined based on their intrinsic value on the date of grant. Expected volatility was estimated by considering historic average share price volatility.

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

 

		Stock option plan				PSU				RSU
Number of options granted			965,823				336,602				298,662
Average strike price		$	19.30				—			$	18.89
Expected dividend		$	0.40				—				—
Expected volatility			32	%			29	%			—
Risk-free interest rate			0.7	%			0.5	%			—
Expected life of option			4.5 years				3 years				—
Expected forfeitures			7	%			5	%			7	%
Weighted average grant date fair values		$	4.30			$	18.88			$	18.89

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

The Company has the following cash-settled plans:

 

A.	Deferred share unit (DSU)

Cameco offers a DSU plan to non-employee directors. A DSU is a notional unit that reflects the market value of a single common share of Cameco. 60% of each director’s annual retainer is paid in DSUs. In addition, on an annual basis, directors can elect to receive 25%, 50%, 75% or 100% of the remaining 40% of their annual retainer and any additional fees in the form of DSUs. If a director meets their ownership requirements, the director may elect to take 25%, 50%, 75% or 100% of their annual retainer and any fees in cash, with the balance, if any, to be paid in DSUs. Each DSU fully vests upon award. The DSUs will be redeemed for cash upon a director leaving the board. The redemption amount will be based upon the weighted average of the closing prices of the common shares of Cameco on the TSX for the last 20 trading days prior to the redemption date multiplied by the number of DSUs held by the director. As of December 31, 2015, the total number of DSUs held by participating directors was 623,534 (2014 - 542,391).

 

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B.	Phantom stock option

Cameco makes annual grants of bonuses to eligible non-North American employees in the form of phantom stock options. Employees receive the equivalent value of shares in cash when exercised. Options granted under the phantom stock option plan have an award value equal to the closing price quoted on the TSX for the common shares of Cameco on the trading day prior to the date on which the option is granted. The options vest over three years and expire eight years from the date granted. As of December 31, 2015, the number of options held by participating employees was 290,833 (2014 - 223,053) with exercise prices ranging from $19.30 to $39.53 per share (2014 - $19.37 to $46.88) and a weighted average exercise price of $26.05 (2014 - $28.81).

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

 

		2015				2014
Deferred share unit plan		$	(1,088	)		$	(1,493	)
Phantom stock option plan			77				(123	)
		$	(1,011	)		$	(1,616	)

At December 31, 2015, a liability of $11,063,000 (2014 - $10,675,000) was included in the consolidated statements of financial position to recognize accrued but unpaid expenses for cash-settled plans.

Fair value measurement of cash-settled plans

The fair value of the phantom stock option plan was measured based on the Black-Scholes option-pricing model. Expected volatility is estimated by considering historic average share price volatility. The inputs used in the measurement of the fair values of the phantom stock option plan at the grant and reporting dates were as follows:

 

		Grant date March 2, 2015				Reporting date December 31, 2015
Number of units			80,980				290,833
Average strike price		$	19.30			$	26.05
Expected dividend		$	0.40			$	0.40
Expected volatility			33	%			32	%
Risk-free interest rate			0.8	%			0.6	%
Expected life of option			4.6 years				3.4 years
Expected forfeitures			7	%			7	%
Weighted average measurement date fair values		$	4.04			$	1.76

 

26.	Pension and other post-retirement benefits

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

 

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

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

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

Cameco expects to pay $1,665,000 in contributions and letter of credit fees to its defined benefit plans in 2016.

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

The effective date of the most recent valuations for funding purposes on the registered defined benefit pension plans is January 1, 2015. The next planned effective date for valuations is January 1, 2018.

 

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

 

		Pension benefit plans								Other benefit plans
		2015				2014				2015				2014
Fair value of plan assets, beginning of year		$	10,877			$	15,402			$	—			$	—
Interest income on plan assets			406				717				—				—
Return on assets excluding interest income			1,960				188				—				—
Employer contributions			—				10				—				—
Benefits paid			(2,581	)			(5,420	)			—				—
Administrative costs paid			(30	)			(20	)			—				—
Fair value of plan assets, end of year		$	10,632			$	10,877			$	—			$	—
Defined benefit obligation, beginning of year		$	52,440			$	44,386			$	20,107			$	16,947
Current service cost			1,744				2,203				1,195				960
Interest cost			1,627				1,940				813				825
- demographic assumptions			—				971				38				106
- financial assumptions			(1,007	)			5,992				(1,228	)			2,037
- experience adjustment			(195	)			2,192				1,671				(180	)
Past service cost			—				2,374				—				—
Benefits paid			(3,175	)			(6,674	)			(825	)			(588	)
Foreign exchange			1,562				(944	)			—				—
Defined benefit obligation, end of year		$	52,996			$	52,440			$	21,771			$	20,107
Defined benefit liability [note 16]		$	(42,364	)		$	(41,563	)		$	(21,771	)		$	(20,107	)

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

 

		Pension benefit plans
		2015				2014
Asset category(a)
Canadian equity securities			8	%			7	%
Global equity securities			16	%			13	%
Canadian fixed income			25	%			21	%
Other(b)			51	%			59	%
Total			100	%			100	%

 

(a)	The defined benefit plan assets contain no material amounts of related party assets at December 31, 2015 and 2014 respectively.

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

 

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

 

		Pension benefit plans								Other benefit plans
		2015				2014				2015				2014
Current service cost		$	1,744			$	2,203			$	1,195			$	960
Net interest cost			1,221				1,223				813				825
Past service cost			—				2,374				—				—
Administration cost			30				20				—				—
Defined benefit expense [note 19]			2,995				5,820				2,008				1,785
Defined contribution pension expense [note 19]			17,961				17,274				—				—
Net pension and other benefit expense		$	20,956			$	23,094			$	2,008			$	1,785

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

 

		Pension benefit plans								Other benefit plans
		2015				2014				2015				2014
Actuarial loss (gain)		$	(1,202	)		$	9,155			$	481			$	1,963
Return on plan assets excluding interest income			(1,960	)			(188	)			—				—
		$	(3,162	)		$	8,967			$	481			$	1,963

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

 

		Pension benefit plans								Other benefit plans
		2015				2014				2015				2014
Discount rate - obligation			3.9	%			3.4	%			4.0	%			3.9	%
Discount rate - expense			3.4	%			4.4	%			3.9	%			4.8	%
Rate of compensation increase			3.0	%			3.0	%			—				—
Initial health care cost trend rate			—				—				7.0	%			7.0	%
Cost trend rate declines to			—				—				5.0	%			5.0	%
Year the rate reaches its final level			—				—				2021				2018
Dental care cost trend rate			—				—				5.0	%			5.0	%

At December 31, 2015, the weighted average duration of the defined benefit obligation for the pension plans was 19.6 years (2014 - 20.3 years) and for the other benefit plans was 15.0 years (2014 - 14.0 years).

 

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

 

		Pension benefit plans								Other benefit plans
		Increase				Decrease				Increase				Decrease
Discount rate		$	(6,449	)		$	8,412			$	(2,985	)		$	3,791
Rate of compensation increase			2,553				(2,307	)			n/a				n/a

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

The methods and assumptions used in preparing the sensitivity analyses are the same as the methods and assumptions used in determining the financial position of Cameco’s plans as at December 31, 2015. The sensitivity analyses are determined by varying the sensitivity assumption and leaving all other assumptions unchanged. Therefore, the sensitivity analyses do not recognize any interdependence in the assumptions. The methods and assumptions used in determining the above sensitivity are consistent with the methods and assumptions used in the previous year.

In addition, an increase of one year in the expected lifetime of plan participants in the pension benefit plans would increase the defined benefit obligation by $1,207,000.

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

 

27.	Financial instruments and related risk management

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

Market risk

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

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

Cameco’s actual exposure to these market risks is constantly changing as the Company’s portfolios of foreign currency, interest rate and commodity contracts change.

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

 

A.	Commodity price risk

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

 

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

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

 

B.	Foreign exchange risk

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

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

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

 

				Carrying value
		Currency		(Cdn)				Gain (loss)
Cash and cash equivalents		USD			123,089				6,154
Accounts receivable		USD			212,433				10,622
Long-term receivables, investments and other		USD			90,634				4,532
Accounts payable and accrued liabilities		USD			(127,111	)			(6,356	)
Net foreign currency derivatives		USD			(167,060	)			(87,746	)

A 5% strengthening of the Canadian dollar against the currencies above at December 31, 2015 would have had an equal but opposite effect on the amounts shown above, assuming all other variables remained constant.

 

C.	Interest rate risk

The Company has a strategy of minimizing its exposure to interest rate risk by maintaining target levels of fixed and variable rate borrowings. The proportions of outstanding debt carrying fixed and variable interest rates are reviewed by senior management to ensure that these levels are within approved policy limits. At December 31, 2015, the proportion of Cameco’s outstanding debt that carries fixed interest rates is 80% (2014 - 80%).

Cameco is exposed to interest rate risk through its interest rate swap contracts whereby fixed rate payments on a notional amount of $300,000,000 of the Series D senior unsecured debentures were swapped for variable rate payments. The swaps terminate on September 2, 2019. Under the terms of the swaps, Cameco makes interest payments based on the three-month Canada Dealer Offered Rate plus an average margin of 3.7% and receives fixed interest payments of 5.67%. At December 31, 2015, the fair value of Cameco’s interest rate swap assets was $10,783,000 (2014 - $2,978,000).

 

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

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

 

		Gain (loss)
Interest rate contracts		$	(3,029	)
Advances receivable from Inkai			794

No amounts were drawn against NUKEM’s revolving loan facility as of December 31, 2015.

Counterparty credit risk

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

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

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

 

		2015				2014
Cash and cash equivalents		$	458,604			$	566,583
Accounts receivable			240,626				435,479
Advances receivable from Inkai [note 32]			87,188				91,672
Derivative assets			11,143				3,889
Other			3,446				—

At December 31, 2015, there were no significant concentrations of credit risk and no amounts were held as collateral. Historically, Cameco has experienced minimal customer defaults and, as a result, considers the credit quality of its accounts receivable to be high. All accounts receivable at the reporting date are neither past due nor impaired.

Cameco has established programs for sales without recourse of trade accounts receivable to financial institutions. Through these programs, the Company surrenders the control, risks and benefits associated with the accounts receivable sold. The amount of receivables sold is recorded as a sale of financial assets and the balances are removed from the consolidated statement of financial position at the time of sale. The total amount of receivables sold under these programs and derecognized in accordance with IAS 39 during 2015 was $201,992,000 ($152,410,000 (USD)) (2014 - $145,477,000 ($130,295,000 (USD)).

Liquidity risk

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

 

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The table below outlines the Company’s available debt facilities at December 31, 2015:

 

						Outstanding and
		Total amount				committed				Amount available
Unsecured revolving credit facility		$	1,250,000			$	—			$	1,250,000
Letter of credit facilities			1,490,809				1,384,061				106,748
NUKEM multicurrency revolving loan facility			112,718				562				112,156

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

 

		Carrying amount				Contractual cash flows				Due in less than 1 year				Due in 1-3 years				Due in 3-5 years				Due after 5 years
Accounts payable and accrued liabilities		$	317,856			$	317,856			$	317,856			$	—			$	—			$	—
Dividends payable			39,579				39,579				39,579				—				—				—
Long-term debt			1,492,237				1,500,000				—				—				500,000				1,000,000
Foreign currency contracts			167,420				167,420				167,420				—				—				—
Other derivative liabilities			816				816				816				—				—				—
Total contractual repayments		$	2,017,908			$	2,025,671			$	525,671			$	—			$	500,000			$	1,000,000

 

		Total				Due in less than 1 year				Due in 1-3 years				Due in 3-5 years				Due after 5 years
Total interest payments on long-term debt		$	544,380			$	69,390			$	138,780			$	110,430			$	225,780

Measurement of fair values

 

A.	Accounting classifications and fair values

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

 

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At December 31, 2015

 

		Fair value through profit or loss				Loans and receivables				Available for sale				Other financial liabilities				Total
Financial assets
Cash and cash equivalents		$	—			$	458,604			$	—			$	—			$	458,604
Accounts receivable [note 7]			—				246,865				—				—				246,865
Derivative assets [note 11]
Foreign currency contracts			360				—				—				—				360
Interest rate contracts			10,783				—				—				—				10,783
Investments in equity securities [note 11]			—				—				938				—				938
Advances receivable from Inkai [note 32]			—				87,188				—				—				87,188
Other			—				3,446				—				—				3,446
		$	11,143			$	796,103			$	938			$	—			$	808,184
Financial liabilities
Accounts payable and accrued liabilities [note 13]		$	—			$	—			$	—			$	317,856			$	317,856
Dividends payable			—				—				—				39,579				39,579
Derivative liabilities [note 16]
Foreign currency contracts			167,420				—				—				—				167,420
Other			816				—				—				—				816
Long-term debt [note 15]			—				—				—				1,492,237				1,492,237
			168,236				—				—				1,849,672				2,017,908
Net		$	(157,093	)		$	796,103			$	938			$	(1,849,672	)		$	(1,209,724	)

At December 31, 2014

 

		Fair value through profit or loss				Loans and receivables				Available for sale				Other financial liabilities				Total
Financial assets
Cash and cash equivalents		$	—			$	566,583			$	—			$	—			$	566,583
Accounts receivable [note 7]			—				455,002				—				—				455,002
Derivative assets [note 11]
Foreign currency contracts			911				—				—				—				911
Interest rate contracts			2,978				—				—				—				2,978
Investments in equity securities [note 11]			—				—				6,601				—				6,601
Advances receivable from Inkai [note 32]			—				91,672				—				—				91,672
		$	3,889			$	1,113,257			$	6,601			$	—			$	1,123,747
Financial liabilities
Accounts payable and accrued liabilities [note 13]		$	—			$	—			$	—			$	316,258			$	316,258
Dividends payable			—				—				—				39,579				39,579
Derivative liabilities [note 16]
Foreign currency contracts			67,916				—				—				—				67,916
Long-term debt [note 15]			—				—				—				1,491,198				1,491,198
			67,916				—				—				1,847,035				1,914,951
Net		$	(64,027	)		$	1,113,257			$	6,601			$	(1,847,035	)		$	(791,204	)

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

 

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

As at December 31, 2015

 

						Fair value
		Carrying value				Level 1				Level 2				Total
Derivative assets [note 11]
Foreign currency contracts		$	360			$	—			$	360			$	360
Interest rate contracts			10,783				—				10,783				10,783
Investments in equity securities [note 11]			938				938				—				938
Derivative liabilities [note 16]
Foreign currency contracts			(167,420	)			—				(167,420	)			(167,420	)
Other			(816	)			—				(816	)			(816	)
Long-term debt [note 15]			(1,492,237	)			—				(1,786,567	)			(1,786,567	)
Net		$	(1,648,392	)		$	938			$	(1,943,660	)		$	(1,942,722	)

As at December 31, 2014

 

						Fair value
		Carrying value				Level 1				Level 2				Total
Derivative assets [note 11]
Foreign currency contracts		$	911			$	—			$	911			$	911
Interest rate contracts			2,978				—				2,978				2,978
Investments in equity securities [note 11]			6,601				6,601				—				6,601
Derivative liabilities [note 16]
Foreign currency contracts			(67,916	)			—				(67,916	)			(67,916	)
Long-term debt [note 15]			(1,491,198	)			—				(1,765,178	)			(1,765,178	)
Net		$	(1,548,624	)		$	6,601			$	(1,829,205	)		$	(1,822,604	)

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

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

 

B.	Financial instruments measured at fair value

Cameco measures its derivative financial instruments, material investments in equity securities and long-term debt at fair value. Investments in publicly held equity securities are classified as a recurring level 1 fair value measurement while derivative financial instruments and long-term debt are classified as a recurring level 2 fair value measurement.

The fair value of investments in equity securities is determined using quoted share prices observed in the principal market for the securities as of the reporting date. The fair value of Cameco’s long-term debt is determined using quoted market yields as of the reporting date, which ranged from 0.6% to 2.2% (2014 - 1.2% to 2.3%).

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

 

53

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

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

 

C.	Financial instruments not measured at fair value

The carrying value of Cameco’s cash and cash equivalents, accounts receivable and accounts payable and accrued liabilities approximates its fair value as a result of the short-term nature of the instruments.

Derivatives

The following table summarizes the fair value of derivatives and classification on the consolidated statements of financial position:

 

		2015				2014
Non-hedge derivatives:
Foreign currency contracts		$	(167,060	)		$	(67,005	)
Interest rate contracts			10,783				2,978
Other			(816	)			—
Net		$	(157,093	)		$	(64,027	)
Classification:
Current portion of long-term receivables, investments and other [note 11]		$	3,823			$	500
Long-term receivables, investments and other [note 11]			7,320				3,389
Current portion of other liabilities [note 16]			(168,236	)			(53,873	)
Other liabilities [note 16]			—				(14,043	)
Net		$	(157,093	)		$	(64,027	)

The following table summarizes the different components of the losses on derivatives included in net earnings:

 

		2015				2014
Non-hedge derivatives:
Foreign currency contracts		$	(292,039	)		$	(126,069	)
Interest rate contracts			10,708				4,893
Other			721				16
Net		$	(280,610	)		$	(121,160	)

 

28.	Capital management

Cameco’s capital structure reflects our vision and the environment in which we operate. We seek growth through development and expansion of existing assets by acquisition. Our capital resources are managed to support achievement of our goals. The overall objectives for managing capital in 2015 remained unchanged from the prior comparative period.

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

 

54

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The capital structure at December 31 was as follows:

 

		2015				2014
Long-term debt [note 15]		$	1,492,237			$	1,491,198
Cash and cash equivalents			(458,604	)			(566,583	)
Net debt			1,033,633				924,615
Non-controlling interest			(1,741	)			160
Shareholders’ equity			5,547,020				5,443,644
Total equity			5,545,279				5,443,804
Total capital		$	6,578,912			$	6,368,419

Cameco is bound by certain covenants in its general credit facilities. These covenants place restrictions on total debt, including guarantees and set minimum levels for net worth. As of December 31, 2015, Cameco met these requirements.

The terms of NUKEM’s revolving loan facility contain a financial covenant that places restrictions on total debt and working capital balances. The facility also requires Cameco, as guarantor, to maintain a minimum credit rating. As of December 31, 2015 the Company is in compliance with all requirements under this facility.

 

29.	Segmented information

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

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

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

 

55

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A.	Business segments - 2015

For the year ended December 31, 2015

 

		Uranium				Fuel services				NUKEM				Other				Total
Revenue		$	1,866,198			$	318,999			$	553,665			$	15,516			$	2,754,378
Expenses
Cost of products and services sold			989,239				226,854				516,880				11,842				1,744,815
Depreciation and amortization			269,084				30,670				(5,103	)			17,867				312,518
Cost of sales			1,258,323				257,524				511,777				29,709				2,057,333
Gross profit (loss)			607,875				61,475				41,888				(14,193	)			697,045
Administration			—				—				18,130				168,680				186,810
Impairment charges			215,488				—				—				—				215,488
Exploration			40,259				—				—				—				40,259
Research and development			—				—				—				6,587				6,587
Loss on disposal of assets			1,753				564				9				—				2,326
Finance costs			—				—				4,593				99,022				103,615
Loss (gain) on derivatives			—				—				(587	)			281,197				280,610
Finance income			—				—				(3	)			(5,414	)			(5,417	)
Share of loss from equity-accounted investees			758				—				—				—				758
Other expense (income)			4,600				—				1,899				(61,222	)			(54,723	)
Earnings (loss) before income taxes			345,017				60,911				17,847				(503,043	)			(79,268	)
Income tax recovery																			(142,630	)
Net earnings																			63,362
Capital expenditures for the year		$	344,610			$	13,952			$	—			$	—			$	358,562

 

56

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For the year ended December 31, 2014

 

		Uranium				Fuel services				NUKEM				Other				Total
Revenue		$	1,777,180			$	306,235			$	349,245			$	(35,128	)		$	2,397,532
Expenses
Cost of products and services sold			902,813				237,872				319,369				(39,286	)			1,420,768
Depreciation and amortization			272,632				30,038				7,584				28,729				338,983
Cost of sales			1,175,445				267,910				326,953				(10,557	)			1,759,751
Gross profit (loss)			601,735				38,325				22,292				(24,571	)			637,781
Administration			—				—				16,591				159,794				176,385
Impairment charges			143,078				183,615				—				—				326,693
Exploration			46,565				—				—				—				46,565
Research and development			—				—				—				5,044				5,044
Gain (loss) on disposal of assets			32,959				11,808				(5	)			—				44,762
Finance costs			—				—				4,428				107,425				111,853
Loss on derivatives			—				—				1,799				119,361				121,160
Finance income			—				—				(14	)			(7,388	)			(7,402	)
Share of loss from equity-accounted investees			3,874				13,267				—				—				17,141
Other expense (income)			(68,626	)			18,035				(659	)			(34,072	)			(85,322	)
Earnings (loss) before income taxes			443,885				(188,400	)			152				(374,735	)			(119,098	)
Income tax recovery																			(175,268	)
Net earnings from continuing operations																			56,170
Capital expenditures for the year		$	466,332			$	13,776			$	—			$	—			$	480,108

 

B.	Geographic segments

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

 

		2015				2014
United States		$	2,135,977			$	1,914,583
Canada			341,568				308,327
Germany			276,833				174,622
		$	2,754,378			$	2,397,532

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

 

		2015				2014
Canada		$	3,867,740			$	4,048,009
Australia			684,261				643,986
United States			429,815				409,495
Other			327,847				274,527
Germany			135,627				116,106
		$	5,445,290			$	5,492,123

 

57

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C.	Major customers

Cameco relies on a small number of customers to purchase a significant portion of its uranium concentrates and uranium conversion services. During 2015, revenues from one customer of Cameco’s uranium, fuel services and NUKEM segments represented approximately $320,312,000 (2014 - $281,485,000), approximately 12% (2014 - 12%) of Cameco’s total revenues from these segments. As customers are relatively few in number, accounts receivable from any individual customer may periodically exceed 10% of accounts receivable depending on delivery schedule.

 

30.	Group entities

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

 

		Principal place		Ownership interest
		of business		2015				2014
Subsidiaries:
Cameco Fuel Manufacturing Inc.		Canada			100	%			100	%
Cameco Inc.		US			100	%			100	%
Power Resources, Inc.		US			100	%			100	%
Crow Butte Resources, Inc.		US			100	%			100	%
NUKEM Investments GmbH		Germany			100	%			100	%
Cameco Australia Pty. Ltd.		Australia			100	%			100	%
Cameco Europe Ltd.		Switzerland			100	%			100	%
Associates
GE-Hitachi Global Laser Enrichment LLC		US			24.00	%			24.00	%
UEX Corporation		Canada			20.33	%			21.28	%

 

31.	Joint operations

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

 

58

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

 

		Principal place of business		Ownership				2015				2014
Total assets
McArthur River		Canada			69.81	%		$	1,107,017			$	1,074,501
Key Lake		Canada			83.33	%			629,075				645,186
Cigar Lake		Canada			50.03	%			1,674,805				1,617,101
Inkai		Kazakhstan			60.00	%			436,611				359,554
								$	3,847,508			$	3,696,342
Total liabilities
McArthur River					69.81	%		$	49,986			$	54,170
Key Lake					83.33	%			174,654				181,443
Cigar Lake					50.03	%			39,201				52,580
Inkai					60.00	%			176,163				171,198
								$	440,004			$	459,391

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

 

32.	Related parties

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

Transactions with key management personnel

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

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

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

Compensation for key management personnel was comprised of:

 

		2015				2014
Short-term employee benefits		$	20,271			$	19,922
Post-employment benefits			5,787				8,395
Share-based compensation(a)			12,749				11,306
		$	38,807			$	39,623

 

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

 

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Other related party transactions

Through unsecured shareholder loans, Cameco has agreed to fund Inkai’s project development costs as well as further evaluation on block 3. The limits of the loan facilities are $189,218,000 (US) and advances under these facilities bear interest at a rate of LIBOR plus 2%. At December 31, 2015, $157,492,000 (US) of principal and interest was outstanding (2014 - $197,551,000 (US)).

Cameco’s share of outstanding principal and interest was $87,188,000 at December 31, 2015 (2014 - $91,672,000) (note 11). For the year ended December 31, 2015, Cameco recorded interest income of $2,007,000 relating to this balance (2014 - $2,038,000).

 

60

Management’s discussion and analysis

February 5, 2016

 

6		2015 PERFORMANCE HIGHLIGHTS
8		MARKET OVERVIEW AND 2015 DEVELOPMENTS
14		OUR STRATEGY
21		MEASURING OUR RESULTS
23		FINANCIAL RESULTS
51		OUR OPERATIONS AND PROJECTS
80		MINERAL RESERVES AND RESOURCES
85		ADDITIONAL INFORMATION
88		2015 CONSOLIDATED FINANCIAL STATEMENTS

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our audited consolidated financial statements (financial statements) and notes for the year ended December 31, 2015. The information is based on what we knew as of February 4, 2016.

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

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

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

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

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Caution about forward-looking information

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

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

 

•

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

 

•

It represents our current views, and can change significantly.

 

•

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

 

•

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

 

•

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

Examples of forward-looking information in this MD&A

 

 

Material risks

 

 

 

2    CAMECO CORPORATION

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Material assumptions

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    3

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4    CAMECO CORPORATION

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MANAGEMENT’S DISCUSSION AND ANALYSIS    5

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2015 performance highlights

Cameco performed well in 2015, navigating the challenging market conditions, while continuing to prepare for the positive long-term growth we see coming in the industry.

Financial performance

 

HIGHLIGHTS
DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED)		2015				2014				CHANGE
Revenue			2,754				2,398				15	%
Gross profit			697				638				9	%
Net earnings attributable to equity holders			65				185				(65	)%
$ per common share (diluted)			0.16				0.47				(65	)%
Adjusted net earnings (non-IFRS, see page 25)			344				412				(17	)%
$ per common share (adjusted and diluted)			0.87				1.04				(16	)%
Cash provided by operations (after working capital changes)			450				480				(6	)%

Net earnings attributable to equity holders (net earnings) and adjusted net earnings were lower in 2015 compared to 2014. However, significant weakness in the Canadian dollar in 2015 resulted in record annual consolidated revenue of $2.8 billion, and record annual revenue from our uranium segment of $1.9 billion based on sales of 32.4 million pounds at a record Canadian dollar average realized price of $57.58 per pound. See 2015 consolidated financial results beginning on page 24 for more information.

 

 

Solid progress in our uranium segment this year

In our uranium segment, we exceeded our annual production expectations, and realized a number of successes at our mining operations. Key highlights:

 

•

record annual production of 28.4 million pounds—4% higher than the guidance provided in our 2015 third quarter MD&A

 

•

record quarterly production of 9.6 million pounds in the fourth quarter—17% higher than in 2014, largely due to production from Cigar Lake

 

•

exceeded planned production at the Cigar Lake mine and AREVA’s McClean Lake mill

We continued to advance exploration activities, spending $2 million on four brownfield exploration projects, $4 million on our projects under evaluation in Australia, and $2 million at Inkai and our US operations. We spent about $32 million on regional exploration programs, mostly in Saskatchewan and Australia.

Updates on our other segments and investments

Production in 2015 from our fuel services segment was 16% lower than in 2014. We continue to face weak market conditions for conversion services, and have decided to further reduce production at Port Hope in 2016.

 

6    CAMECO CORPORATION

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On January 31, 2014, we announced the sale of our 31.6% limited partnership interest in Bruce Power Limited Partnership (BPLP) and related entities for $450 million. The sale closed on March 27, 2014, and was accounted for as being completed effective January 1, 2014.

 

HIGHLIGHTS						2015				2014				CHANGE
Uranium		Production volume (million lbs)					28.4				23.3				22	%
		Sales volume (million lbs)1					32.4				33.9				(4	)%
		Average realized price		($US/lb)			45.19				47.53				(5	)%
				($Cdn/lb)			57.58				52.37				10	%
		Revenue ($ millions)1					1,866				1,777				5	%
		Gross profit ($ millions)					608				602				1	%
Fuel services		Production volume (million kgU)					9.7				11.6				(16	)%
		Sales volume (million kgU)1					13.6				15.5				(12	)%
		Average realized price		($Cdn/kgU)			23.37				19.70				19	%
		Revenue ($ millions)1					319				306				4	%
		Gross profit ($ millions)					61				38				61	%
NUKEM		Sales volume U3O8 (million lbs)1					10.7				8.1				32	%
		Average realized price		($Cdn/lb)			48.82				44.90				9	%
		Revenue ($ millions)1					554				349				59	%
		Gross profit ($ millions)					42				22				91	%

 

1	Includes sales and revenue between our uranium, fuel services and NUKEM segments. Please see 2015 Financial results by segment beginning on page 43.

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    7

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Market overview and 2015 developments

The world needs energy

It’s no secret the world needs more energy. The world’s population increasing from 7 billion to 9 billion over the next two decades will drive the need for energy, but, even today, there are 2 billion people who lack access to electricity or have only limited access. This is unacceptable in today’s modern world, where electricity is one of the greatest contributors to quality of life. Many countries are working to fill that gap and, in many cases, to keep up with rapid growth. Nuclear energy is an important option in the world’s energy mix, and, as energy demand continues to grow, nuclear is expected to do the same.

 

Nuclear – an integral part of the energy mix

Today, nuclear power contributes 11% of global electricity. While that percentage is not expected to change significantly over the next two decades, nuclear power output is expected to change—increasing along with rising electricity demand. In other words, the nuclear story is a growth story.

It’s easy to see why. Nuclear power is a safe, clean, reliable, affordable, and, most importantly, baseload energy source. As a result, it is an integral part of the energy mix for many countries, and even more so as the focus on climate change and clean air intensifies. Not only does it provide baseload power—that 24-hour power required to have health care, education, transportation, and communication systems—but it does so without emitting greenhouse gases (GHGs).

Reactors – gigawatt growth

That’s why, today, we see billions of dollars being invested in nuclear around the world. By 2025, we expect to see around 113 new reactors built, more than 60 of which are under construction right now. In addition, some existing plants are also adding capacity through uprates. Although this growth will be tempered somewhat by the closure of around 55 reactors, the end result is growth in the range of 80 gigawatts of nuclear power added to the world’s grids over the next decade, and even more expected outside that time frame.

 

 

8    CAMECO CORPORATION

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The areas of the world where we are seeing the most growth are those with increasing populations and rapidly expanding economies. China continues to lead the way with 24 reactors under construction. India, Russia, South Korea, United Arab Emirates (UAE), and the United States are also building new reactors. Of the reactors under construction today, if startups occur as planned, 65% of those units could be online over the next three years.

Elsewhere, the United Kingdom (UK) government is maintaining its commitment to nuclear energy as a source of emissions-free energy. Critical milestones have been reached, allowing new build plans to move forward. In addition, several previously non-nuclear countries are moving ahead with their reactor construction programs or considering adding nuclear to their energy mix in the future. Construction continues on four units in the UAE. Turkey is also moving forward with plans to build eight new reactors. Bangladesh, Vietnam, Jordan, Poland, Saudi Arabia, and Egypt are a few more of the countries continuing their plans to proceed with nuclear power development.

 

As we expand our 10-year market analysis by one year, the net new reactor count at the end of the window changes from about 80 net new reactors previously expected by 2024, to about 58 net new reactors expected by 2025. Although this change in growth expectations impacts the expected demand in the later years of our industry outlook, it does not influence our view of the market fundamentals and is primarily a function of rolling our analysis forward. This year, the change is related to:

 

•

a number of new reactors that came online in 2015 and are now in the “Operable” category, rather than the “New build” category

 

•

several reactors that are scheduled to be shut down in 2025, which are now included in our 10-year window, as well as additional shutdowns announced in 2015, increasing the “Retirements” category

 

•

low electricity prices and flat demand, in conjunction with delays in finalizing energy policies, contributing to the announcement of construction delays for some reactors in the outermost years of the 10-year window, pushing the affected units beyond 2025 and removing them from the current “New build” category

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    9

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More reactors means more demand for uranium

Today, the world’s reactors consume around 160 million pounds of uranium annually. With the growth in reactor construction, we expect that to grow to around 220 million pounds per year by 2025—average annual growth of 3%. This does not include the strategic inventory building that usually occurs with new reactor construction, which would mean even further growth in demand. So, over the long term, we see very strong growth in the demand for the products that we supply.

Can supply keep up?

Over the long term, while demand is increasing, supply, without new investment, is expected to decrease, resulting in the possibility of a widening gap between supply and demand.

 

There is already a gap between the uranium consumed by reactors and the uranium produced from the world’s mines, which has been the case for several years. That gap has been bridged by secondary supplies—uranium in various forms that is already out of the ground and sitting in stockpiles around the world. Today, about 20% of global supply comes from secondary sources, but those stockpiles are being drawn down, and are expected to contribute less and less over time. This means that more primary production will be needed from uranium mines—in fact, we estimate about 10% of total supply required over the next decade will need to come from new mines that are not yet in development.

 

But that could be difficult. In general, new mines are difficult to bring on in a timely manner. The long lead nature of mine development means our industry is not able to respond quickly to sudden increases in demand or significant supply interruptions. Bringing on and ramping up a significant new production centre can take between seven and 10 years.

 

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Adding to the challenge are the number of new projects being cancelled or delayed, and the existing production being shelved due to the low uranium prices that have persisted since the 2011 events at the Fukushima-Daiichi nuclear power plant in Japan. Today’s uranium prices are not high enough to incent new mine production and, in some cases, not high enough to keep current mines in operation. While some new mines may be brought on regardless of price as a result of sovereign interests or to cover existing commitments, overall, we expect supply to decrease over time due to the global lack of investment.

Today – little demand, a lot of supply

Today, the uranium market continues to be in a state of oversupply, and there are a number of factors contributing: primary supply continues to perform relatively well; enrichers are underfeeding their plants in reaction to excess enrichment capacity, which creates another source of uranium; the majority of Japan’s reactors remain idled, meaning their inventories continue to grow and Japanese utilities will be well covered for some time; and the new reactors under construction today have not yet started to consume the inventories that have been purchased and stored for their operation.

In addition, market activity is much lighter than it has been in the past. Utilities are well covered in their fuel requirements and are not under pressure to contract for more. They have time to wait it out to see if uranium prices continue to decrease. So far, this strategy has paid off for them. Similarly, existing suppliers appear reluctant to enter into meaningful contract volumes at current prices. The result has been very low levels of contracting over the past three years. Consumption is a fairly simple and constant equation based on the fuel needs of operating reactors and, historically, the quantity of material contracted in the long-term market in a year has been roughly equivalent to the quantity of uranium consumed in the world’s reactors in a year. In fact, only 35% of the uranium consumed in nuclear reactors over the past three years has been replaced by utilities with long-term contracts. That’s less than 180 million pounds contracted when about 475 million pounds were used, meaning inventories and the current oversupply are being drawn down as future requirements remain uncovered. If contracting is not happening now, it will have to later; the demand has just been pushed further out in time.

2015 market developments

THE GOOD, THE BAD AND THE INDIFFERENT

As has been the case in recent years, a lot happened over the course of 2015, although the general state of the market did not see much change.

Making positive news for nuclear, as usual, was China. Not only did the country continue with its rapid reactor new build program and bring eight reactors online, but Chinese companies also signed agreements with Argentina, Romania and the UK for new reactors, illustrating the country’s commitment to nuclear and its intent to become a major international player in the nuclear industry.

Undoubtedly, the biggest headline of 2015 was the long-awaited first reactor restarts in Japan. Sendai units 1 and 2 were the first reactors in Japan to restart since 2013, and it is hoped they are the first of many to come.

New builds in the UK and US continued to be bright spots for the industry, in addition to a number of reactor life extensions approved in Japan, and the US, with utilities now considering additional extensions that could see reactor lives reaching 80 years.

However, these positive developments could not outweigh the more powerful influence of a continued sluggish global economy, geopolitical issues, concerns around growth in China, and flat electricity demand. These more general drivers had help from industry specific factors as well, such as slower new reactor construction, eight reactor shutdowns, the continued high level of inventories held by market participants, and France’s policy to reduce nuclear in their energy mix to 50% by 2025 becoming law.

In addition, supply performed relatively well, with only minor disruptions and one curtailment, unlike 2014, which saw six projects tempered or curtailed.

The end result was a market seemingly indifferent to the commotion of events that occurred throughout the year.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    11

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CONTRACTING

Market contracting activity was modest. Spot volumes were normal, but long-term contracting was well below historical averages and current consumption levels—about half of current annual reactor consumption estimates, similar to 2014. Long-term contracting is a key factor in the timing of market recovery, and its pace will depend on the respective coverage levels, market views and risk appetite of both buyers and sellers.

 

JAPAN

The big news in Japan was the restart of Sendai units 1 and 2, which occurred in August and October. In addition, the court injunction against the two Takahama units was overturned in December, 2015, clearing the way for Takahama unit 3 to restart on January 29, 2016, with unit 4 expected to restart later in the first quarter. Ikata unit 3 has also cleared a safety inspection by the Nuclear Regulatory Authority, and four more units are in the final stages of approval. In all, three reactors are now in operation, while 23 remain under evaluation for restart.

Over the long term, Japan’s energy policy states that nuclear will make up 20 to 22% of the energy mix in the country. The billions of dollars in investment being made by Japan’s utilities suggest a high degree of confidence in reactors coming back online and meeting this target; however, public sentiment towards nuclear in Japan remains somewhat uncertain.

OTHER REGIONS

China’s remarkable nuclear growth program remains on track and the UK’s plans for new reactor construction continue to move forward. India and South Korea are also among several key regions growing their nuclear generation fleet.

In 2015, growth was tangible as 10 reactors came online—double that of 2014. These included the eight noted in China, one in Russia and one in South Korea. And seven more reactors began construction—six in China and one in the UAE, a formerly non-nuclear country with four reactors now under construction.

But, to round out the picture, eight units shut down. Five of these were in Japan, plus one in Sweden, one in Germany as part of its phase-out plans, and one in the UK—the last Magnox reactor operating in the world. In addition, there were announcements for future shutdowns in the US, where nuclear struggles to remain competitive in deregulated electricity markets and in the context of low natural gas prices.

One event that could have an effect on the future of nuclear in the US and other western countries is the UN Climate Conference COP-21 agreement, finalized in 2015. As a non-GHG emitter, nuclear could play a significant role in achieving climate change prevention goals.

 

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Industry prices

In 2015, the spot price declined from a high of $39 (US) per pound to a low of about $34 (US) per pound, but managed to average around $37 (US) for the year. Utilities continue to be well covered under existing contracts, and, given the current uncertainties in the market, we expect they and other market participants will continue to be opportunistic in their buying. As a result, contracting is expected to remain somewhat discretionary in 2016.

 

		2015				2014				CHANGE
Uranium ($US/lb U3O8)1
Average spot market price			36.55				33.21				10	%
Average long-term price			46.29				46.46				—
Fuel services ($US/kgU as UF6)1
Average spot market price
North America			7.35				7.63				(4	)%
Europe			7.85				7.97				(2	)%
Average long-term price
North America			15.33				16.00				(4	)%
Europe			16.38				17.00				(4	)%

Note: the industry does not publish UO₂ prices.

 

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

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    13

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Our strategy

Positioned for success

Our strategy is set within the context of a challenging market environment, which we expect to give way to strong long-term fundamentals driven by increasing population and electricity demand.

We are a pure-play nuclear fuel producer, focused on taking advantage of the long-term growth we see coming in our industry, while maintaining the ability to respond to market conditions as they evolve. Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals in order to increase long-term shareholder value, and to do that with an emphasis on safety, people and the environment.

URANIUM

Uranium production is central to our strategy, as it is the biggest value driver of the nuclear fuel cycle and our business. We plan to focus on our tier-one assets and manage our supply according to market conditions in order to return the best value possible. As conditions improve, we expect to meet rising demand with increased production from our best margin operations. See Uranium – production overview on page 54 for additional details.

FUEL SERVICES

Our fuel services division is a source of profit and supports our uranium segment while allowing us to vertically integrate across the fuel cycle. Our focus is on maintaining and optimizing profitability.

ENRICHMENT

We continue to explore opportunities in the second largest value driver of the fuel cycle.

NUKEM

NUKEM’s activities provide a source of profit and give us insight into market dynamics.

Capital allocation – focus on value

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

 

•

create the greatest long-term value for our shareholders

 

•

allow us to maintain our investment grade rating

 

•

ensure we execute on our dividend policy

To deliver value, free cash flow must be productively reinvested in the business or returned to shareholders, which requires good execution and disciplined allocation. We have a multidisciplinary capital allocation team that evaluates all possible uses of investable capital.

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.

Today, considering the continued near-term uncertainty, we believe the best way to create value is to focus on expanding our tier-one assets and maintaining a strong balance sheet. This provides us with the opportunity to gain operating leverage as the market transitions to being demand driven, and mitigates risk in the event of a prolonged period of uncertainty.

REINVESTMENT

Before investable capital is reinvested in sustaining, capacity replacement or growth, all opportunities are ranked and only those that meet the required risk-adjusted return criteria are considered for investment. We also must identify, at the corporate level, the expected impact on cash flow, earnings and the balance sheet. All project risks must be identified, including the risks of not investing. Allocation of capital only occurs once an investment has cleared these hurdles.

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

 

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RETURN

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

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

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

Marketing strategy – balanced contract portfolio

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

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

In addition, we are active in the spot market, buying and selling uranium when it is beneficial for us. Our NUKEM business segment enhances our ability to participate, as they are one of the world’s leading traders of uranium and uranium-related products. We undertake activity in the spot market prudently, looking at the spot price and other business factors to decide whether it is appropriate to purchase or sell into the spot market. Not only is this activity a source of profit, it gives us insight into underlying market fundamentals.

OPTIMIZING REALIZED PRICE

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

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

LONG-TERM CONTRACTING

We target a ratio of 40% fixed-pricing and 60% market-related pricing in our portfolio of long-term contracts. This is a balanced and flexible approach that allows us to adapt to market conditions and put a floor on our average realized price, reduce the volatility of our future earnings and cash flow, and deliver the best value to shareholders over the long term.

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

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

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    15

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

CONTRACT PORTFOLIO STATUS

Currently, we are heavily committed under long-term uranium contracts through 2018, so we are being selective when considering new commitments. We have commitments to sell approximately 190 million pounds of U₃O₈ with 41 customers worldwide in our uranium segment, and commitments to sell approximately 65 million kilograms as UF₆ conversion with 33 customers worldwide in our fuel services segment.

Customers – U₃O₈:

Five largest customers account for 47% of commitments

 

Customers – UF₆ conversion:

Five largest customers account for 59% of commitments

 

MANAGING OUR CONTRACT COMMITMENTS

To meet our delivery commitments, we use uranium obtained:

 

•

from our existing production

 

•

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

 

•

from our existing inventory

We allow sales volumes to vary year-to-year depending on:

 

•

the level of sales commitments in our long-term contract portfolio (the annual average sales commitments over the next five years in our uranium segment is 27 million pounds, with commitment levels through 2018 higher than in 2019 and 2020)

 

•

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

 

•

purchases under existing and/or new arrangements

 

•

discretionary use of inventories

 

•

market opportunities

 

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Focusing on cost efficiency

PRODUCTION COSTS

In order to operate efficiently and cost-effectively, we manage operating costs and improve plant reliability by prudently investing in production infrastructure, new technology and business process improvements. Like all mining companies, our uranium segment is affected by the cost of inputs such as labour and fuel.

 

Operating costs in our fuel services segment are mainly fixed. In 2015, labour accounted for about 51% of the total. The largest variable operating cost is for zirconium, followed by energy (natural gas and electricity), and anhydrous hydrogen fluoride.

PURCHASES AND INVENTORY COSTS

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

To meet our delivery commitments, we make use of our mined production and inventories, and we purchase material where it is beneficial to do so. The cost of purchased material may be higher or lower than our other sources of supply, depending on market conditions. The cost of purchased material affects our cost of sales, which is determined by calculating the average of all of our sources of supply, including opening inventory, production and purchases.

FINANCIAL IMPACT

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 primary production to meet growing demand, which should have a positive impact on our average realized price.

In addition, as we execute our strategy to focus on tier-one production, we expect to see more stability in the unit cost of sales for our uranium segment.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    17

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Sustainable development: A key part of our strategy

Social responsibility and environmental protection are top priorities for us, so much so that we have built our corporate objectives around them within our four measures of success: a safe, healthy and rewarding workplace, a clean environment, supportive communities, and outstanding financial performance. For us, sustainability isn’t an add-on for our company; it’s at the core of our company culture. It helps us:

 

•

build trust, credibility and corporate reputation

 

•

gain and enhance community support for our operations and plans

 

•

attract and retain employees

 

•

manage risk

 

•

drive innovation and continual improvement to build competitive advantage

Because they are so important, we integrate sustainable development principles and practices at each level of our organization, from our overall corporate strategy to individual employee practice in day-to-day operations.

SAFE, HEALTHY, REWARDING WORKPLACE

We are committed to living a strong safety culture, while looking to continually improve. As a result of this commitment, we have a long history of strong safety performance at our operations and across the organization.

2015 Highlights:

 

•

our total recordable injury rate decreased by 10%

 

•

continued low average dose of radiation to workers while moving Cigar Lake into commercial production

 

•

awarded the John T Ryan National Safety award for McArthur River mine based on prior year performance

 

•

top employer awards

A CLEAN ENVIRONMENT

We are committed to being a leading environmental performer. We strive to be a leader not only by complying with legal requirements, but also by keeping risks as low as reasonably achievable, and looking for opportunities to move beyond requirements.

We track our progress by monitoring the air, water and land near our operations, and by measuring the amount of energy we use and the amount of waste generated. We use this information to help identify opportunities to improve.

2015 Highlights:

 

•

sustained the significantly reduced uranium-to-air emissions achieved at our Port Hope Conversion facility in 2014

 

•

implemented waste management initiatives across the organization, including significant reductions of low level radioactive waste stored at our Fuel Services Division facilities

 

•

achieved a 50% reduction of surface water consumption at our McArthur River operation through increased recycling initiatives

 

•

carried out industry leading research and innovation in groundwater restoration at our US in situ recovery operations

SUPPORTIVE COMMUNITIES

Gaining the trust and support of our communities, indigenous people, and governments is necessary to sustain our business. We earn support and trust through excellent safety and environmental performance, by proactively engaging our stakeholders in an open and transparent way, and by making a difference in communities wherever we operate. These efforts are critical to obtaining and maintaining the necessary regulatory approvals.

2015 Highlights:

 

•

over $299 million in procurement from locally owned northern Saskatchewan companies

 

•

1,369 local personnel from northern Saskatchewan (811 Cameco employees, 558 contractors)

 

•

no significant disputes related to land use or customary rights

 

•

community engagement activities at all of our operations

 

•

established relationships with five universities along with Los Alamos National Laboratory, and the United States Geological Survey in conducting groundwater restoration

 

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OUTSTANDING FINANCIAL PERFORMANCE

Long-term financial stability and profitability are essential to our sustainability as a company. We firmly believe that sound governance is the foundation for strong corporate performance.

2015 Highlights:

 

•

continue to achieve an average realized price that outperforms the market

 

•

ranked 26th out of 234 Canadian companies by Globe and Mail in governance practices

MONITORING AND MEASUREMENT

We take the integration of sustainable development and measurement of our performance seriously. We have been producing a Sustainable Development (SD) Report since 2005, using the Global Reporting Initiative’s Sustainability Framework (GRI). It is our report card to our stakeholders. It tells them how we’re performing against globally recognized key indicators that measure our social, environmental and economic impacts in the areas that matter most to them. It provides information about our goals, where we’ve met, exceeded or struggled with them, and how we plan to do better. We expect to release our next SD Report in 2016.

All of our operating sites are ISO 14001 compliant. In addition, we have now transitioned from individual site-based ISO 14001 certifications to a single corporate certification. We expect to roll the majority of our operations into this single certification.

Achievements

We are a four-time Gold award winner through the Progressive Aboriginal Relations program as judged by the Canadian Council for Aboriginal Business. We are also proud to have been named one of Canada’s Top 100 Employers, Saskatchewan’s Top Employers, Canada’s Best Diversity Employers and one of Canada’s Top Employers for Young People for the sixth year. We are a leading employer of indigenous peoples in Canada, and have procured over $3 billion in services from local suppliers in northern Saskatchewan since 2004. This year, we were also named one of the world’s most sustainable corporations by Corporate Knights, a Canadian media and research company.

In 2015, we secured approval to increase production at the McArthur River operation as a result of earning the confidence of our regulators, which—although primarily based on our safety, health and environmental performance—is also a reflection of the support we have from our neighbouring communities in northern Saskatchewan.

We encourage you to review our SD report at cameco.com/about/sustainability which outlines our commitment to people and the environment in more detail.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    19

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Measuring our results

There is no finish line when it comes to delivering on our strategic goals. We have a long-term commitment to constantly measure, evaluate and improve.

Each year, we set corporate objectives that are aligned with our strategic plan. These objectives fall under our four measures of success, and performance against specific targets under these objectives forms the foundation for a portion of annual employee and executive compensation. See our most recent management proxy circular for more information on how executive compensation is determined.

 

2015 OBJECTIVES1		TARGET		RESULTS
OUTSTANDING FINANCIAL PERFORMANCE
Earnings measures		Achieve targeted adjusted net earnings and cash flow from operations.		Partially achieved		•       adjusted net earnings were lower than the target   •       cash flow from operations was higher than the target
Capital management measures		Execute capital projects within the approved scope, cost and schedule.		Achieved		•       cost performance was below the target level (under budget)   •       project milestones were achieved on or ahead of schedule
Cigar Lake		Achieve production target at Cigar Lake.		Exceeded		•       production from Cigar Lake in 2015 was higher than the target
SAFE, HEALTHY AND REWARDING WORKPLACE
Workplace safety		Strive for no injuries at all Cameco-operated sites. Maintain a long-term downward trend in combined employee and contractor injury frequency and severity, and radiation doses.		Partially achieved		•       did not meet our targeted safety measures   •       injury rates trended downward across the company, but fell short of targets for the year   •       average radiation doses remained low and stable
Rewarding workplace		Attract and retain the employees needed to support operations.		Substantially achieved		•       overall voluntary turnover rate was better than target (lower turnover)   •       turnover rate for new hires during the first year of employment was higher than the target (higher turnover)
CLEAN ENVIRONMENT
Improve environmental performance		Achieve a decreasing trend for environmental incidents.		Achieved		•       there were no significant environmental incidents in 2015   •       reportable environmental incidents were within the range of targeted performance
SUPPORTIVE COMMUNITIES
Build and sustain stakeholder support		Meet our business development obligations under our Collaboration Agreements.		Exceeded		•       sourcing of northern services from northern Saskatchewan vendors was above the target   •       sourcing of capital projects construction services from northern Saskatchewan vendors was above the target

 

1	Detailed results for our 2015 corporate objectives and the related targets will be provided in our 2016 management proxy circular prior to our Annual Meeting of Shareholders on May 11, 2016.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    21

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2016 objectives

 

OUTSTANDING FINANCIAL PERFORMANCE

•    Achieve targeted adjusted net earnings and cash flow from operations.   •    Achieve capital project management targets and continue to ramp up production at Cigar Lake.

SAFE, HEALTHY AND REWARDING WORKPLACE

•    Improve workplace safety performance at all sites.   •    Attract and retain the employees needed to support operations.

CLEAN ENVIRONMENT

•    Improve environmental performance at all sites.

SUPPORTIVE COMMUNITIES

•    Build and sustain strong stakeholder support for our activities.

 

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Financial results

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

 

24		2015 CONSOLIDATED FINANCIAL RESULTS
35		OUTLOOK FOR 2016
37		LIQUIDITY AND CAPITAL RESOURCES
42		BALANCE SHEET
43		2015 FINANCIAL RESULTS BY SEGMENT
43		URANIUM
45		FUEL SERVICES
45		NUKEM
46		FOURTH QUARTER FINANCIAL RESULTS
46		CONSOLIDATED RESULTS
48		URANIUM
50		FUEL SERVICES
50		NUKEM

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    23

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2015 consolidated financial results

On January 31, 2014, we announced the sale of our 31.6% limited partnership interest in BPLP and related entities for $450 million. The sale closed on March 27, 2014 and has been accounted for as being completed effective January 1, 2014.

Under IFRS, we are required to report the results from discontinued operations separately from continuing operations. We have included our operating earnings from BPLP, and the financial impact of the sale, in discontinued operations.

Throughout this document, for comparison purposes, all results for “earnings from continuing operations” and “cash from continuing operations” have been revised to exclude BPLP. The impact of BPLP is shown separately as a discontinued operation.

 

HIGHLIGHTS														CHANGE FROM
DECEMBER 31 ($ MILLIONS EXCEPT WHERE INDICATED)		2015				2014				2013				2014 TO 2015
Revenue			2,754				2,398				2,439				15	%
Gross profit			697				638				607				9	%
Net earnings attributable to equity holders			65				185				318				(65	)%
$ per common share (basic)			0.16				0.47				0.81				(65	)%
$ per common share (diluted)			0.16				0.47				0.81				(65	)%
Adjusted net earnings (non-IFRS, see page 25)			344				412				445				(17	)%
$ per common share (adjusted and diluted)			0.87				1.04				1.12				(16	)%
Cash provided by operations (after working capital changes)			450				480				524				(6	)%

Net earnings

Our net earnings attributable to equity holders (net earnings) in 2015 were $65 million ($0.16 per share diluted) compared to $185 million ($0.47 per share diluted) in 2014, mainly due to:

 

•

greater losses on foreign exchange derivatives due to the weakening of the Canadian dollar. See Foreign exchange on page 34 for details.

 

•

lower tax recoveries, primarily due to the write-off of our deferred tax asset in the US. See Income taxes on page 29 for details.

partially offset by:

 

•

lower impairment charges ($215 million in 2015; $327 million in 2014)

 

•

higher earnings in our uranium and fuel services segments due to higher average realized prices

 

•

higher earnings in our NUKEM segment as a result of higher volumes and average realized price

 

•

reduction of the provision related to our CRA litigation. See Income taxes on page 29 for details.

In addition, in 2014 there were a number of one-time items that contributed to the higher net earnings in 2014 compared to 2015, including:

 

•

the sale of our interest in BPLP resulting in a $127 million gain in 2014

 

•

a favourable settlement of $66 million in 2014 with respect to a dispute regarding a long-term supply contract with a utility customer

partially offset by:

 

•

payment of an early agreement termination fee of $18 million as a result of the cancellation of our toll conversion agreement with Springfields Fuels Limited (SFL), and $12 million for settlement costs with respect to early redemption of our Series C debentures in 2014

 

•

the write-off of $41 million of assets under construction in 2014 as a result of changes made to the scope of a number of projects

THREE-YEAR TREND

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

 

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In 2014, our net earnings were $133 million lower than in 2013 primarily due to:

 

•

an increase in impairment charges ($70 million in 2013; $327 million in 2014)

 

•

no earnings from BPLP, which we divested in the first quarter of 2014

 

•

the write-off of $41 million of assets under construction as a result of changes made to the scope of a number of projects

 

•

payment of an early termination fee of $18 million incurred as a result of our toll conversion agreement with SFL, and settlement costs of $12 million with respect to early termination of our Series C debentures

 

•

lower earnings from our fuel services business as a result of a decrease in sales volumes and higher unit cost of sales

 

•

higher losses on foreign exchange derivatives due to the weakening Canadian dollar. See Foreign exchange on page 34 for more information.

partially offset by:

 

•

a $127 million gain on the sale of our interest in BPLP in 2014

 

•

higher earnings from our uranium segment due to a higher average realized price

 

•

a favourable settlement of $66 million in a dispute regarding a long-term supply contract with a utility customer

 

•

lower exploration costs

 

•

higher tax recoveries resulting from higher pre-tax losses in Canada

Impairment charge on producing assets

During the fourth quarter of 2015, we recognized a $210 million impairment charge related to our Rabbit Lake operation. The impairment was due to increased uncertainty around future production sources for the Rabbit Lake mill as a result of the ongoing economic conditions. The amount of the charge was determined as the excess of carrying value over the recoverable amount. The recoverable amount of the mill was determined to be $69 million. See note 9 to the financial statements.

Non-IFRS measures

ADJUSTED NET EARNINGS

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

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

To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the years ended 2015, 2014 and 2013.

 

($ MILLIONS)				2015				2014				2013
Net earnings attributable to equity holders					65				185				318
Adjustments
Adjustments on derivatives (pre-tax)					166				47				56
NUKEM purchase price inventory recovery					(3	)			(5	)			14
Impairment charges					215				327				70
Income taxes on adjustments					(99	)			(56	)			(28	)
Write-off of assets					—				41				—
Loss on exploration properties					—				—				15
Gain on interest in BPLP (after tax)					—				(127	)			—
Adjusted net earnings					344				412				445

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    25

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The following table shows what contributed to the change in adjusted net earnings for 2015.

 

($ MILLIONS)
Adjusted net earnings – 2014					412
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			(27	)
		Lower realized prices ($US)			(76	)
		Foreign exchange impact on realized prices			245
		Higher costs			(136	)
		change – uranium			6
Fuel services		Lower sales volume			(5	)
		Higher realized prices ($Cdn)			50
		Higher costs			(22	)
		change – fuel services			23
NUKEM		Gross profit			20
		change – NUKEM			20
Other changes
Higher administration expenditures					(10	)
Lower exploration expenditures					6
Lower income tax recovery					(76	)
Contract termination fee (SFL) incurred in 2014					18
Arbitration award in 2014					(66	)
Debenture redemption premium incurred in 2014					12
Lower loss on disposal of assets					1
Higher loss on derivatives					(40	)
Lower loss on equity-accounted investments					16
Higher foreign exchange gains					25
Other					(3	)
Adjusted net earnings – 2015					344

THREE-YEAR TREND

Our adjusted net earnings decreased from 2013 to 2014, and decreased again from 2014 to 2015.

The 7% decrease from 2013 to 2014 resulted from:

 

•

no earnings from BPLP due to divestiture of our interest in the first quarter of 2014

 

•

an early termination fee of $18 million incurred as a result of the cancellation of our toll conversion agreement with SFL, which was to expire in 2016

 

•

settlement costs of $12 million with respect to the early redemption of our Series C debentures

 

•

lower earnings from our fuel services business as a result of lower sales volumes and higher unit cost of sales

 

•

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

partially offset by:

 

•

higher earnings in our uranium segment due to a higher average realized price

 

•

a favourable settlement of $66 million with respect to a dispute regarding a long-term supply contract with a utility customer

 

•

lower exploration costs due to a more focused effort on our core projects in Saskatchewan, with decreases in activity elsewhere, particularly at our Kintyre project in Australia and at Inkai

The 17% decrease from 2014 to 2015 resulted from:

 

•

greater losses on foreign exchange derivatives due to the weakening of the Canadian dollar, see Foreign exchange on page 34 for more information

 

•

lower tax recoveries, primarily due to the write-off of our deferred tax asset in the US. See Income taxes on page 29 for details.

 

26    CAMECO CORPORATION

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partially offset by:

 

•

higher earnings in our uranium and fuel services segments mainly due to a higher average realized price

 

•

higher earnings from our NUKEM segment mainly due to higher sales volumes and a higher average realized price

 

•

a reduction of the provision related to our CRA litigation, see Income taxes on page 29 for details

In addition, in 2014 there was a favourable settlement of $66 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher adjusted net earnings in 2014 compared to 2015. The impact of the settlement was partially offset by an early termination fee of $18 million incurred as a result of the cancellation of our toll conversion agreement with SFL and settlement costs of $12 million with respect to the early redemption of our Series C debentures in 2014.

Average realized prices

 

																CHANGE FROM
				2015				2014				2013				2014 TO 2015
Uranium1		$US/lb			45.19				47.53				48.35				(5	)%
		$Cdn/lb			57.58				52.37				49.81				10	%
Fuel services		$Cdn/kgU			23.37				19.70				18.12				19	%
NUKEM		$Cdn/lb			48.82				44.90				42.26				9	%

 

1	Average realized foreign exchange rate ($US/$Cdn): 2015 – $1.27, 2014 – $1.10 and 2013 – $1.03.

Revenue

The following table shows what contributed to the change in revenue for 2015.

 

($ MILLIONS)
Revenue – 2014			2,398
Uranium
Lower sales volume			(80	)
Higher realized prices ($Cdn)			169
Change in intersegment sales			48
Fuel services
Lower sales volume			(37	)
Higher realized prices ($Cdn)			50
Change in intersegment sales			4
NUKEM
Change in revenue			204
Change in intersegment sales			23
Other			(25	)
Revenue – 2015			2,754

See 2015 Financial results by segment on page 43 for more detailed discussion.

THREE-YEAR TREND

In 2014, revenue decreased by 2% compared to 2013 due to lower sales revenues in our NUKEM and fuel services segments as we reduced sales volumes in response to market conditions. This was partially offset by higher revenues in our uranium business due to a higher average realized price for uranium resulting from the weakening of the Canadian dollar compared to 2013. The realized foreign exchange rate was 1.10 compared to 1.03 in 2013.

In the third quarter of 2015, we projected our annual revenue to increase between 5% and 10%, but realized a 15% increase over 2014. One contributing factor was higher revenue in our NUKEM segment as a result of higher than expected sales volumes, which were driven by increased market activity in the fourth quarter. In addition, sales revenues in all of our operating segments increased compared to 2014 due to higher realized prices resulting from the weakening of the Canadian dollar. The realized foreign exchange rate was 1.27 compared to 1.10 in 2014.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    27

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OUTLOOK FOR 2016

We expect consolidated revenue to decrease up to 5% in 2016, based on currently committed sales volumes, due to a planned decrease in uranium and fuel services sales volumes. If we make additional sales with deliveries in 2016, we would expect our revenue outlook to increase.

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries. As a result, our quarterly delivery patterns and, therefore, our sales volumes and revenue can vary significantly as shown below. We expect the quarterly distribution of uranium deliveries in 2016 to be weighted to the second half of the year. However, not all delivery notices have been received to date and the expected delivery pattern could change. Typically, we receive notices six months in advance of the requested delivery date.

 

Discontinued operation

On March 27, 2014, we completed the sale of our 31.6% limited partnership interest in BPLP, which was accounted for effective January 1, 2014. The aggregate sale price for our interest in BPLP and certain related entities was $450 million. We realized an after tax gain of $127 million on this divestiture. As a result of the transaction, we presented the results of BPLP as a discontinued operation and we revised our statement of earnings, statement of comprehensive income and statement of cash flows to reflect the change in presentation. See note 6 to the financial statements for more information.

 

($ MILLIONS)		2015				2014
Share of earnings from BPLP and related entities			—				—
Tax expense			—				—
			—				—
Gain on disposal of BPLP and related entities			—				145
Tax expense on disposal			—				(18	)
			—				127
Net earnings from discontinued operations			—				127

Corporate expenses

ADMINISTRATION

 

($ MILLIONS)		2015				2014				CHANGE
Direct administration			173				163				6	%
Stock-based compensation			14				13				8	%
Total administration			187				176				6	%

Direct administration costs in 2015 were $10 million higher than in 2014 due to costs related to our collaboration agreement with the startup of Cigar Lake, increased legal costs as our CRA dispute progresses toward trial, and the effect of foreign exchange on our US subsidiaries.

 

28    CAMECO CORPORATION

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We recorded $14 million in stock-based compensation expenses this year under our stock option, restricted share unit, deferred share unit, performance share unit and phantom stock option plans, compared to $13 million in 2014. See note 25 to the financial statements.

Outlook for 2016

We expect administration costs (not including stock-based compensation) to be 5% to 10% higher compared to 2015 due to increased costs related to the northern collaboration agreements and increased project work. In 2016, we are continuing to negotiate new collaboration agreements with northern communities, which could result in additional one-time payments. Due to the uncertainty of the timing for the potential signing of agreements, the cost is not included in our outlook. If agreements are signed and there is an impact on our administrative costs, we will update our outlook.

EXPLORATION

Our 2015 exploration activities remained focused on Canada and Australia. As we continued to focus more on our core projects in Saskatchewan, and reduced our activities elsewhere, we decreased our spending from $47 million in 2014 to $40 million in 2015.

Outlook for 2016

We expect exploration expenses to be about 15% to 20% higher than they were in 2015 due to increased exploration activity at Cigar Lake.

FINANCE COSTS

Finance costs were $104 million compared to $112 million in 2014. The decrease from last year was a result of $12 million in settlement costs related to the early redemption of our Series C debentures being incurred in 2014, partially offset by higher interest on long-term debt in 2015. See note 20 to the financial statements.

FINANCE INCOME

Finance income was $5 million compared to $7 million in 2014, reflecting lower average cash balances in 2015.

GAINS AND LOSSES ON DERIVATIVES

In 2015, we recorded $281 million in losses on our derivatives compared to losses of $121 million in 2014. The increase reflects the continued weakening of the Canadian dollar compared to the US dollar in 2015. See Foreign exchange on page 34 and note 27 to the financial statements.

INCOME TAXES

We recorded an income tax recovery of $143 million in 2015 compared to a recovery of $175 million in 2014. The decrease in recovery was primarily due to the write-off of our deferred tax asset in the US, partially offset by a reduction in the provision related to our CRA litigation and a change in the distribution of earnings between jurisdictions compared to 2014. See note 22 to the financial statements.

During the fourth quarter, we reversed amounts related to our deferred tax asset in the US totaling $73 million. We determined that it was no longer probable that there would be sufficient taxable profit in the future against which the operating losses and other tax deductions could be used.

The recovery was impacted by a decrease of $42 million to our provision related to the CRA litigation. Since 2008, CRA has disputed our corporate structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2010 tax returns. We have recorded a cumulative tax provision of $50 million (September 30, 2015 - $92 million), where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through 2015. We have reduced the provision to reflect management’s revised estimate, which takes into account additional contract information. We are confident that we will be successful in our case and continue to believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution. See note 22 to the financial statements.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    29

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In 2015, we recorded losses of $960 million in Canada compared to $841 million in 2014, while earnings in foreign jurisdictions increased to $880 million from $722 million. The tax rate in Canada is higher than the average of the rates in the foreign jurisdictions in which our subsidiaries operate.

In the third quarter, we expected our annual income tax rate, based on adjusted net earnings, to be a recovery of 25% to 30%. The actual result was a recovery of 15%, mainly due to one-time adjustments as discussed above. On an adjusted earnings basis, we recognized a tax recovery of $44 million in 2015 compared to a recovery of $120 million in 2014. Our effective tax rate was a recovery of 15% in 2015, compared to a recovery of 41% in 2014. The table below presents our adjusted earnings and adjusted income tax expenses attributable to Canadian and foreign jurisdictions.

 

($ MILLIONS)		2015				2014
Pre-tax adjusted earnings1
Canada			(578	)			(611	)
Foreign			877				901
Total pre-tax adjusted earnings			299				290
Adjusted income taxes1
Canada			(177	)			(156	)
Foreign			133				36
Adjusted income tax recovery			(44	)			(120	)

 

1	Pre-tax adjusted earnings and adjusted income taxes are non-IFRS measures. Our IFRS-based measures have been adjusted by the amounts reflected in the table in adjusted net earnings (non-IFRS measure on page 25).

TRANSFER PRICING DISPUTES

We have been reporting on our transfer pricing disputes with CRA since 2008, when it originated, and with the United States Internal Revenue Service (IRS) since the first quarter of 2015. Below, we discuss the general nature of transfer pricing disputes and, more specifically, the ongoing disputes we have.

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

 

•

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

 

•

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

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

For the years 2003 to 2010, CRA has shifted CEL’s income (as recalculated by CRA) back to Canada and applied statutory tax rates, interest and instalment penalties, and, from 2007 to 2009, transfer pricing penalties. There has not yet been a decision regarding a transfer pricing penalty for 2010. The IRS is also proposing to allocate a portion of CEL’s income for the years 2009 through 2012 to the US, resulting in such income being taxed in multiple jurisdictions. Taxes of approximately $320 million for the 2003 – 2015 years have already been paid in a jurisdiction outside Canada and the US. Bilateral international tax treaties contain provisions that generally seek to prevent taxation of the same income in both countries. As such, in connection with these disputes, we are considering our options, including remedies under international tax treaties that would limit double taxation; however, there is a risk that we will not be successful in eliminating all potential double taxation. The expected income adjustments under our tax disputes are represented by the amounts claimed by CRA and IRS and are described below.

 

30    CAMECO CORPORATION

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CRA dispute

Since 2008, CRA has disputed our corporate structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements. To the end of 2014, we received notices of reassessment for our 2003 through 2009 tax returns, and, in the fourth quarter of 2015, we received a notice of reassessment for our 2010 tax year. We have recorded a cumulative tax provision of $50 million (September 30, 2015 - $92 million), where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through 2015. We have reduced the provision to reflect management’s revised estimate, which takes into account additional contract information. We are confident that we will be successful in our case and continue to believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

For the years 2003 through 2010, CRA issued notices of reassessment for approximately $3.4 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $1.1 billion. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229 million. The Canadian income tax rules include provisions that require larger companies like us to remit or otherwise secure 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions, we have paid a net amount of $232 million cash. In addition, we have provided $332 million in letters of credit (LC) to secure 50% of the cash taxes and related interest amounts reassessed in 2015. The amounts paid or secured are shown in the table below.

 

YEAR PAID ($ MILLIONS)		CASH TAXES				INTEREST AND INSTALMENT PENALTIES				TRANSFER PRICING PENALTIES				TOTAL				CASH REMITTANCE				SECURED BY LC
Prior to 2013			—				13				—				13				13				—
2013			1				9				36				46				46				—
2014			106				47				—				153				153				—
2015			202				71				79				352				20				332
Total			309				140				115				564				232				332

Using the methodology we believe CRA will continue to apply, and including the $3.4 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $7.0 billion of additional income taxable in Canada for the years 2003 through 2015, which would result in a related tax expense of approximately $2.1 billion. As well, CRA may continue to apply transfer pricing penalties to taxation years subsequent to 2009. As a result, we estimate that cash taxes and transfer pricing penalties for these years would be between $1.65 billion and $1.70 billion. In addition, we estimate there would be interest and instalment penalties applied that would be material to us. While in dispute, we would be responsible for remitting or otherwise providing security for 50% of the cash taxes and transfer pricing penalties (between $825 million and $850 million), plus related interest and instalment penalties assessed, which would be material to us.

Under the Canadian federal and provincial tax rules, the amount required to be paid or secured each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers. Recently, the CRA decided to disallow the use of any loss carry-backs for any transfer pricing adjustment, starting with the 2008 tax year. This does not impact the anticipated income tax expense for a particular year, but does impact the timing of any required security or payment. As noted above, for the 2010 tax year, as an alternative to paying cash, we used letters of credit to satisfy our obligations related to the reassessed income tax and related interest amounts. We expect to be able to continue to provide security in the form of letters of credit to satisfy these requirements. The estimated amounts summarized in the table below reflect actual amounts paid or secured and estimated future amounts owing based on the actual and expected reassessments for the years 2003 through 2015, and include the expected timing adjustment for the inability to use any loss carry-backs starting in 2008. We will update this table annually to include the estimated impact of reassessments expected for completed years subsequent to 2015.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    31

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$ MILLIONS		2003-2015				2016-2017				2018-2023				TOTAL
50% of cash taxes and transfer pricing penalties paid, secured or owing in the period
Cash payments			156				155 - 180				30 - 55				335 - 360
Secured by letters of credit			264				95 - 120				20 - 45				425 - 450
Total paid1			420				255 - 280				65 - 90				825 - 850

 

1	These amounts do not include interest and instalment penalties, which totaled approximately $140 million to December 31, 2015.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted, including the $564 million already paid or otherwise secured to date.

We are expecting the trial for the 2003, 2005 and 2006 reassessments to commence during the week of September 26, 2016, with final arguments in April 2017. If this timing is adhered to, we expect to receive a Tax Court decision within six to 18 months after the trial is complete.

IRS dispute

In the fourth quarter of 2015, we received a Revenue Agents Report (RAR) from the IRS for the tax years 2010 to 2012. Similar to the 2009 RAR received in the first quarter of 2015, the IRS is challenging the transfer pricing used under certain intercompany transactions pertaining to the 2010 to 2012 tax years for certain of our US subsidiaries. The 2009 and 2010 to 2012 RARs list the adjustments proposed by the IRS and calculate the tax and any penalties owing based on the proposed adjustments.

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

 

•

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

 

•

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

The proposed adjustments result in an increase in taxable income in the US of approximately $419 million (US) and a corresponding increased income tax expense of approximately $122 million (US) for the 2009 through 2012 taxation years, with interest being charged thereon. In addition, the IRS proposed cumulative penalties of approximately $8 million (US) in respect of the adjustment.

We believe that the conclusions of the IRS in the RARs are incorrect and we are contesting them in an administrative appeal, during which we are not required to make any cash payments. Until this matter progresses further, we cannot provide an estimation of the likely timeline for a resolution of the dispute.

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

Overview of disputes

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

 

		CRA		IRS
Basis for dispute		•       Corporate structure/governance   •       Transfer pricing methodology used for certain intercompany uranium sale and purchase agreements   •       Allocates Cameco Europe Ltd. (CEL) income (as adjusted) for 2003 through 2010 to Canada (same income we paid tax on in foreign jurisdictions and includes income that IRS is proposing to tax)		•       Income earned on sales of uranium by the US mines to CEL is inadequate   •       Compensation earned by Cameco Inc., one of our US subsidiaries, is inadequate   •       Allocates a portion of CEL’s income for the years 2009 through 2012 to the US (a portion of the same income we paid tax on in foreign jurisdictions and which the CRA is proposing to tax)
Years under consideration		•       CRA reassessed 2003 to 2010   •       Auditing 2011 to 2012		•       IRS has proposed adjustments for 2009 through 2012

 

32    CAMECO CORPORATION

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Timing of resolution		•       Expect our appeal of the 2003, 2005 and 2006 reassessments to commence during the week of September 26, 2016, with final arguments expected in April 2017   •       Expect Tax Court decision six to 18 months after completion of trial		•       Contesting proposed adjustments in an administrative appeal   •       We cannot yet provide an estimate as to the timeline for resolution
Required payments		•       Expect to provide security in form of letters of credit and/or make cash payments for 50% of cash taxes, interest and penalties as reassessed   •       Paid $232 million in cash to date   •       Secured $332 million using letters of credit		•       No security or cash payments required while under administrative appeal

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

This discussion of our expectations relating to our tax disputes with CRA and IRS and future tax reassessments by CRA and IRS is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 2 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.

 

 

OUTLOOK FOR 2016

On an adjusted net earnings basis, we expect a tax recovery of 25% to 30% in 2016 from our uranium, fuel services and NUKEM segments.

Our consolidated tax rate is a blend of the statutory rates applicable to taxable income earned or tax losses incurred in Canada and in our foreign subsidiaries. We have a global customer base and we have established a marketing and trading structure involving foreign subsidiaries, which entered into various intercompany purchase and sale arrangements, as well as uranium purchase and sale agreements with third parties. Cameco and its subsidiaries made reasonable efforts to put arm’s-length transfer pricing arrangements in place, and these arrangements expose the parties to the risks and rewards accruing to them under these contracts. The intercompany contract prices are generally comparable to those established in comparable contracts between arm’s-length parties entered into at that time.

This year, many of the existing intercompany purchase and sale arrangements in our portfolio expire. We have started to replace these contracts and will continue to put new intercompany arrangements in place, which, as the existing arrangements did, will reflect the market at the time they are signed.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    33

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As a result, in 2017, we expect our consolidated tax rate will transition to a modest expense, and trend toward a tax expense of approximately 20% over the next five years. The actual effective tax rate will vary from year-to-year, primarily due to the actual distribution of earnings among jurisdictions and the market conditions at the time transactions occur under both our intercompany and third-party purchase and sale arrangements.

FOREIGN EXCHANGE

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

We sell the majority of our uranium and fuel services products under long-term contracts, which are routinely denominated in US dollars, while our production costs are largely denominated in Canadian dollars. To provide cash flow predictability and certainty as we undertake our operating and capital expenditures, we use hedging to try to protect our net exposure (e.g. total sales less US dollar expenses and product purchases) against shorter term exchange rate volatility.

Our risk management policy permits us to hedge 35% to 100% of our expected net exposure over a rolling 60-month period. Our normal practice is to hedge over a three- to four-year period by hedging 50% to 80% of net exposure in the first 12 months with decreasing hedge ratios in subsequent years. The actual hedge position is reflected in Revenue, cash flow and earnings sensitivity analysis provided on page 35.

In the reporting period, some hedge contracts may be settled and the remaining contracts outstanding, we mark-to-market, which can result in reported gains or losses on derivatives for the period depending on the movement in the US/Cdn exchange rate. In periods of rapid currency fluctuations, the average exchange rate under our hedge contracts will lag the market. For example, the average US/Cdn exchange rate for our 2015 hedge position included exchange rates for periods prior to the rapid devaluation of the Canadian dollar and was much lower than the average exchange rate for 2015. As a result, as a Canadian dollar reporter, we reported significant losses on derivatives in 2015. However, over time and as we add hedges at current market rates, we expect to realize the benefit of the weak Canadian dollar as the average exchange rate under our hedge contracts increases. In the event of a rapidly appreciating Canadian dollar, we would see the opposite effect.

Since we use hedging to protect our foreign exchange exposure in a particular period, when we put contracts in place we designate them for use in that period. Therefore, a portion of the reported gains and losses noted above do not apply in the current period. We take this into account in our adjusted net earnings measure, with the goal of better matching the benefits of our hedging activities with the expected foreign currency exposure to which they apply. In our adjusted net earnings measure, we adjust net earnings in the reporting period for one-time items that are not representative of our ongoing operations and to:

 

•

remove mark-to-market gains or losses on the outstanding hedge position at the end of the period

 

•

remove the portion of gains and losses on those contracts that were rolled over in the reporting period for use in a future period

 

•

add back gains and losses previously removed and that apply to the current period

At December 31, 2015:

 

•

The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.38 (Cdn), up from $1.00 (US) for $1.16 (Cdn) at December 31, 2014. The exchange rate averaged $1.00 (US) for $1.28 (Cdn) over the year.

 

•

We had foreign currency forward contracts of $1.0 billion (US), EUR 12 million and foreign currency options of $250 million (US) at December 31, 2015. The US currency forward contracts had an average exchange rate of $1.00 (US) for $1.23 (Cdn) and US currency option contracts had an average exchange rate range of $1.00 (US) for $1.28 to $1.34 (Cdn), and €1.00 for $1.11 (US) for EUR currency contracts.

 

•

The mark-to-market loss on all foreign exchange contracts was $167 million compared to a $67 million loss at December 31, 2014.

We manage counterparty risk associated with hedging by dealing with highly rated counterparties and limiting our exposure. At December 31, 2015, with the exception of the EUR hedge, all of our counterparties to foreign exchange hedging contracts had a Standard & Poor’s (S&P) credit rating of A or better.

 

34    CAMECO CORPORATION

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Outlook for 2016

Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals, while maintaining the ability to respond to conditions as they evolve.

Our outlook for 2016 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 2015 Financial results by segment on page 43 for details.

2016 FINANCIAL OUTLOOK

 

		CONSOLIDATED				URANIUM				FUEL SERVICES				NUKEM
Production			—				30.0 million lbs				8 to 9 million kgU				—
Delivery volume1			—				30 to 32 million lbs	2			Decrease up to 5%				9 to 10 million lbs U3O8
Revenue compared to 20153			Decrease up to 5%				Decrease up to 5%	4			Increase up to 5%				Increase 5% to 10%
Average unit cost of sales (including D&A)			—				Increase up to 5%	5			Increase 10% to 15%				—
Direct administration costs compared to 20156			Increase 5% to 10%				—				—				—
Gross profit			—				—				—				Gross profit 4% to 5%
Exploration costs compared to 2015			—				Increase 15% to 20%				—				—
Tax rate7			Recovery of 25% to 30%				—				—				—
Capital expenditures		$	320 million				—				—				—

 

1	Our 2016 outlook for delivery volume in our uranium and NUKEM segments does not include sales between our uranium, fuel services and NUKEM segments.

2	Our uranium delivery volume is based on the volumes we currently have commitments to deliver under contract in 2016.

3	For comparison of our 2016 outlook and 2015 results for revenue in our uranium and NUKEM segments, we do not include sales between our uranium, fuel services and NUKEM segments.

4	Based on a uranium spot price of $34.65 (US) per pound (the Ux spot price as of February 1, 2016), a long-term price indicator of $44.00 (US) per pound (the Ux long-term indicator on January 25, 2016) and an exchange rate of $1.00 (US) for $1.25 (Cdn).

5	This increase is based on the unit cost of sales for produced material and committed long-term purchases. If we make discretionary purchases in 2016, then we expect the overall unit cost of sales may be affected.

6	Direct administration costs do not include stock-based compensation expenses. See page 28 for more information.

7	Our outlook for the tax rate is based on adjusted net earnings.

REVENUE, CASH FLOW AND EARNINGS SENSITIVITY ANALYSIS

For 2016:

 

•

An increase of $5 (US) per pound in each of the Ux spot price ($34.65 (US) per pound on February 1, 2016) and the Ux long-term price indicator ($44.00 (US) per pound on January 25, 2016) would change revenue by $72 million and net earnings by $56 million. Conversely, a decrease of $5 (US) per pound would decrease revenue by $69 million and net earnings by $54 million.

 

•

A one cent change in the value of the Canadian dollar versus the US dollar would change adjusted net earnings by $8 million and cash flow by $1 million, with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact.

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

The following table and graph 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, 2015 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, 2015, and none of the assumptions we list below change.

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    35

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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
2016			41				46				56				65				75				84				93
2017			39				46				56				67				78				87				94
2018			39				47				58				69				80				90				97
2019			39				47				59				70				79				88				94
2020			42				49				59				70				79				86				93

 

The table and graph illustrate the mix of long-term contracts in our December 31, 2015 portfolio, and are consistent with our marketing strategy. Both have been updated to reflect deliveries made and contracts entered into up to December 31, 2015.

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:

 

 

36    CAMECO CORPORATION

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Liquidity and capital resources

At the end of 2015, we had cash and short-term investments of $459 million in a mix of short-term deposits and treasury bills, while our total debt amounted to $1.5 billion.

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

We expect to continue investing in maintaining and prudently expanding our production capacity over the next several years. We have a number of alternatives to fund future capital requirements, including using our current cash balances, drawing on our existing credit facilities, entering new credit facilities, using our operating cash flow, and raising additional capital through debt or equity financings. We are always considering our financing options so we can take advantage of favourable market conditions when they arise. Due to the cyclical nature of our business, we may need to temporarily draw on other short-term liquidity during the course of the year. However, apart from these short-term fluctuations, we expect our cash balances and operating cash flows will meet our capital requirements during 2016, without the need for significant additional funding.

We have an ongoing dispute with CRA, see page 30 for more information. Until this dispute is settled, we expect to pay cash or provide security in the form of letters of credit for future amounts owing to the Government of Canada for 50% of the cash taxes payable and the related interest and penalties. We have provided an estimate of the amount and timing of the expected cash taxes and transfer pricing penalties paid, secured or owing in the table on page 32.

FINANCIAL CONDITION

 

		2015				2014
Cash position ($ millions)			459				567
(cash and cash equivalents)
Cash provided by continuing operations ($ millions)			450				480
(net cash flow generated by our operating activities after changes in working capital)
Cash provided by operations/net debt			44	%			52	%
(net debt is total consolidated debt, less cash position)
Net debt/total capitalization			16	%			15	%
(total capitalization is net debt and equity)

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, 2015:

 

SECURITY		DBRS				S&P
Commercial paper			R-1 (low)				A-1 (low)	1
Senior unsecured debentures			A (low)				BBB+
Rating trend / rating outlook			Negative				Stable

 

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

DBRS provides guidance for the outlook of the assigned rating using the rating trend. The rating trend represents their assessment of the likelihood and direction that the rating could change in the future, should present tendencies continue, or in some cases, if challenges are not overcome.

S&P uses rating outlooks to assess the potential direction of a long-term credit rating over the intermediate term. Their outlook indicates the likelihood that the rating could change in the future.

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    37

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Liquidity

 

($ MILLIONS)		2015				2014
Cash and cash equivalents at beginning of year			567				188
Cash from operations			450				480
Investment activities
Additions to property, plant and equipment and acquisitions			(359	)			(480	)
Discontinued operation			—				447
Other investing activities			18				12
Financing activities
Change in debt			—				146
Interest paid			(70	)			(78	)
Contributions from non-controlling interest			—				1
Issue of shares			—				6
Dividends			(158	)			(158	)
Exchange rate on changes on foreign currency cash balances			11				3
Cash and cash equivalents at end of year			459				567

CASH FROM CONTINUING OPERATIONS

Cash from continuing operations was 6% lower than in 2014. This was primarily due to the settlement and rollover of contracts in our hedge portfolio which required more cash during 2015 compared to 2014, largely due to the weakening Canadian dollar, offset by higher profits in all of our segments. Not including working capital requirements, our operating cash flows in the year were down $46 million. See note 24 to the financial statements.

INVESTING ACTIVITIES

Cash used in investing includes acquisitions and capital spending.

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.

 

38    CAMECO CORPORATION

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CAMECO’S SHARE ($ MILLIONS)		2015 PLAN1				2015 ACTUAL				2016 PLAN
Sustaining capital
McArthur River/Key Lake			20				16				30
Cigar Lake			10				9				25
Rabbit Lake			35				33				25
US ISR			5				7				5
Inkai			5				1				5
Fuel services			15				13				20
Other			5				5				5
Total sustaining capital			95				84				115
Capacity replacement capital
McArthur River/Key Lake			95				96				55
Cigar Lake			25				26				20
Rabbit Lake			—				—				10
US ISR			30				27				20
Inkai			15				19				15
Total capacity replacement capital			165				168				120
Growth capital
McArthur River/Key Lake			15				13				40
Cigar Lake			90				81				30
Inkai			15				11				10
Fuel services			5				1				5
Other			—				1				—
Total growth capital			125				107				85
Total uranium & fuel services			385	1			359				320

 

1	Capital spending outlook was updated to $385 million in our third quarter MD&A.

Outlook for investing activities

 

CAMECO’S SHARE ($ MILLIONS)		2017 PLAN				2018 PLAN
Total uranium & fuel services			300-350				250-300
Sustaining capital			135-155				95-110
Capacity replacement capital			135-150				145-160
Growth capital			30-45				10-25

We expect total capital expenditures for uranium and fuel services to decrease by about 11% in 2016.

Major sustaining, capacity replacement and growth expenditures in 2016 include:

 

•

McArthur River/Key Lake – At McArthur River, the largest projects are the expansion of freeze capacity and mine development. Other projects include site facility and equipment purchases. At Key Lake, work will be done to expand capacity in the solvent extraction and crystallization circuits of the mill.

 

•

US in situ recovery (ISR) – wellfield construction represents the largest portion of our expenditures in the US.

 

•

Rabbit Lake – At Eagle Point, the largest component is mine development, along with mine equipment upgrades and purchases. At the mill, we plan to optimize tailings capacity and work on various mill facility and equipment replacements.

 

•

Cigar Lake – Work to expand freezing capacity makes up the largest portion of capital at the Cigar Lake site. We are also paying our share of the costs to modify and expand the McClean Lake mill.

We previously expected to spend between $350 million and $400 million in 2017. We now expect to spend between $300 million and $350 million in 2017. Due to the continued market uncertainty, we have reduced growth capital to focus on our tier-one properties.

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.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    39

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FINANCING ACTIVITIES

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

Long-term contractual obligations

 

		2016				2017 AND 2018				2019 AND 2020				2021 AND BEYOND				TOTAL
DECEMBER 31 ($ MILLIONS)
Long-term debt			—				—				500				1,000				1,500
Interest on long-term debt			69				139				110				226				544
Provision for reclamation			13				80				81				801				975
Provision for waste disposal			3				14				—				—				17
Other liabilities			—				—				—				64				64
Capital commitments			55				—				—				—				55
Total			140				233				691				2,091				3,155

We have contractual capital commitments of approximately $55 million at December 31, 2015. Certain of the contractual commitments may contain cancellation clauses; however, we disclose the commitments based on management’s intent to fulfil the contracts.

We have unsecured lines of credit of about $2.7 billion, which include the following:

 

•

A $1.25 billion unsecured revolving credit facility that matures November 1, 2019. 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, 2015, there were no amounts outstanding under this facility.

 

•

Approximately $1.4 billion in 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, for our obligations relating to the CRA dispute, and as overdraft protection. At December 31, 2015, we had approximately $1.4 billion outstanding in letters of credit.

In total we have $1.5 billion in senior unsecured debentures outstanding:

 

•

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

 

•

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

 

•

$500 million bearing interest at 4.19% per year, maturing on June 24, 2024

 

•

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

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, 2015, we complied with all covenants, and we expect to continue to comply in 2016.

 

40    CAMECO CORPORATION

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NUKEM financing arrangements

NUKEM enters into financing arrangements with third parties where future receivables arising from certain sales contracts are sold to financial institutions in exchange for cash. These arrangements require NUKEM to satisfy its delivery obligations under the sales contracts, which are recognized as deferred sales (see notes 8 and 16 to the financial statements for more information). In addition, NUKEM is required to pledge the underlying inventory as security against these performance obligations. As of December 31, 2015, we had $97.9 million ($70.8 million (US)) of inventory pledged as security under financing arrangements, compared with $94.4 million ($81.4 million (US)) at December 31, 2014.

OFF-BALANCE SHEET ARRANGEMENTS

We had three kinds of off-balance sheet arrangements at the end of 2015:

 

•

purchase commitments

 

•

financial assurances

 

•

other arrangements

Purchase commitments

The table below is based on our purchase commitments at December 31, 2015. These commitments include a mix of fixed price and market-related contracts, and are with entities that buy and sell uranium and uranium-related products. Actual payments will be different as a result of changes to our purchase commitments and, in the case of contracts with market-related pricing, the market prices in effect at the time of purchase. We will update this table as required in our MD&A to reflect changes to our purchase commitments and changes in the prices used to estimate our commitments under market-related contracts.

 

		2016				2017 AND 2018				2019 AND 2020				2021 AND BEYOND				TOTAL
DECEMBER 31 ($ MILLIONS)
Purchase commitments1			1,036				862				391				403				2,692

 

1	Denominated in US dollars, converted to Canadian dollars as of December 31, 2015 at the rate of $1.38.

At the end of 2015, we had committed to $2.7 billion (Cdn) for the following:

 

•

approximately 38 million pounds of U3O8 equivalent from 2016 to 2028

 

•

approximately 4 million kgU as UF6 in conversion services from 2016 to 2019

 

•

about 1 million Separative Work Units (SWU) of enrichment services to meet existing forward sales commitments under agreements with a non-Western supplier

The suppliers do not have the right to terminate agreements other than pursuant to customary events of default provisions.

Financial assurances

Standby letters of credit mainly provide financial assurance for the decommissioning and reclamation of our mining and conversion facilities as well as for our obligations relating to the CRA dispute. We are required to provide letters of credit to various regulatory agencies until decommissioning and reclamation activities are complete. We are also planning to provide letters of credit until the CRA dispute is resolved. Letters of credit are issued by financial institutions for a one-year term. At December 31, 2015 our financial assurances totaled $1.4 billion compared to $0.9 billion at December 31, 2014. The increase is mainly due to:

 

•

increased requirements for decommissioning letters of credit for Key Lake ($80 million)

 

•

obligations relating to the CRA dispute ($332 million)

 

•

exchange rate fluctuations ($65 million)

Other arrangements

We entered into a factoring arrangement where receivables arising from certain sales contracts are sold to a financial institution. Upon the sale, we assign the rights to the accounts receivable to the financial institution without recourse. This arrangement provides immediate access to cash and requires we collect payment from our customers and remit the payments to the financial institution. Expenses incurred under the arrangement are recognized within finance costs in the consolidated statement of earnings.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    41

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In addition, NUKEM enters into arrangements with third parties where receivables arising from certain sales contracts are sold to financial institutions in exchange for cash. Upon the sale, NUKEM assigns the rights to the accounts receivable to the financial institution without recourse. These arrangements require NUKEM to satisfy its delivery obligations under the sales contracts; however, the customer is responsible for making payment directly to the financial institution. The discount at which the financial institution purchases the receivable is offset against the revenue NUKEM records on delivery of the product to the customer.

BALANCE SHEET

 

DECEMBER 31, ($ MILLIONS EXCEPT PER SHARE AMOUNTS)		2015				2014				2013				CHANGE 2014 TO 2015
Inventory			1,285				902				913				42	%
Total assets			8,795				8,473				8,039				4	%
Long-term financial liabilities			2,500				2,448				1,915				2	%
Dividends per common share			0.40				0.40				0.40				—

Total product inventories increased by 42% to $1.3 billion this year due to higher levels of inventory for our uranium segment, where the quantities sold were lower than the quantities produced and purchased for the year. In 2015, total volume of product inventories for our uranium segment increased by 54%. During the year, we had the opportunity to purchase material at favourable prices, which added to our inventory position. In addition, the average cost of inventory increased by 15% due to the high cost of Cigar Lake production as it ramps up and the cost of material purchased during the year that was higher than the average cost of inventory at the beginning of the year. At December 31, 2015, our average cost for uranium was $36.72 per pound, up from $32.00 per pound at December 31, 2014.

At the end of 2015, our total assets amounted to $8.8 billion, an increase of $0.3 billion compared to 2014, primarily due to higher inventory and an increase in our deferred tax assets. In 2014, the total asset balance increased by $0.4 billion compared to 2013, primarily due to higher deferred tax assets and an increase in long-term receivables related to our CRA litigation.

The major components of long-term financial liabilities are long-term debt, the provision for reclamation, deferred sales and financial derivatives. In 2015, our balance did not change significantly. In 2014, our balance increased by $0.5 billion due to the early redemption of our Series C debentures and the issuance of the Series G debentures, as well as an increase in deferred sales.

 

42    CAMECO CORPORATION

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2015 financial results by segment

Uranium

 

HIGHLIGHTS						2015				2014				CHANGE
Production volume (million lbs)							28.4				23.3				22	%
Sales volume (million lbs)1							32.4				33.9				(4	)%
Average spot price		($	US/lb	)			36.55				33.21				10	%
Average long-term price		($	US/lb	)			46.29				46.46				—
Average realized price		($	US/lb	)			45.19				47.53				(5	)%
		($	Cdn/lb	)			57.58				52.37				10	%
Average unit cost of sales (including D&A)		($	Cdn/lb	)			38.83				34.64				12	%
Revenue ($ millions)1							1,866				1,777				5	%
Gross profit ($ millions)							608				602				1	%
Gross profit (%)							33				34				(3	)%

 

1	Includes sales and revenue between our uranium, fuel services and NUKEM segments (32,000 pounds in sales and revenue of $1.0 million in 2015, 1.4 million pounds in sales and revenue of $48 million in 2014).

Production volumes in 2015 increased by 22% compared to 2014. Lower production at our US ISR operations was more than offset by the rampup of Cigar Lake production. See Uranium – production overview on page 54 for more information.

Uranium revenues this year were up 5% compared to 2014 due to an increase of 10% in the Canadian dollar average realized price, partially offset by a decrease in sales volumes of 4%. The spot price for uranium averaged $36.55 (US) per pound in 2015, an increase of 10% compared to the 2014 average price of $33.21 (US) per pound; however, our US dollar average realized price was lower mainly due to lower prices under fixed price contracts. The effect of foreign exchange resulted in a higher Canadian dollar average realized price than in the prior year. The realized foreign exchange rate was $1.27 compared to $1.10 in 2014.

Total cost of sales (including D&A) increased by 7% ($1.26 billion compared to $1.18 billion in 2014) due to higher unit cost of sales offset by lower sales volumes. The higher unit cost of sales was mainly the result of an increase in the volume of material purchased at prices higher than our average cost of inventory, and an increase in unit production costs related to the addition of higher costs from Cigar Lake during rampup.

The net effect was a $6 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)		2015				2014				CHANGE
Produced
Cash cost			20.62				18.66				11	%
Non-cash cost			11.51				9.30				24	%
Total production cost			32.13				27.96				15	%
Quantity produced (million lbs)			28.4				23.3				22	%
Purchased
Cash cost1			46.02				38.17				21	%
Quantity purchased (million lbs)			12.5				7.1				76	%
Totals
Produced and purchased costs1			36.38				30.34				20	%
Quantities produced and purchased (million lbs)			40.9				30.4				35	%

 

1	Cash costs of purchased material in 2015 were $36.57 (US) per pound compared to $34.51 (US) per pound in 2014. In 2015, the exchange rate on purchases averaged $1.00 (US) for $1.26 (Cdn) compared to $1.00 (US) for $1.11 (Cdn) in 2014.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    43

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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 years ended 2015 and 2014 as reported in our financial statements.

CASH AND TOTAL COST PER POUND RECONCILIATION

 

($ MILLIONS)		2015				2014
Cost of product sold			989.2				902.8
Add / (subtract)
Royalties			(116.5	)			(91.2	)
Standby charges			—				(24.8	)
Other selling costs			(13.8	)			(9.0	)
Change in inventories			301.8				(71.9	)
Cash operating costs (a)			1,160.7				705.9
Add / (subtract)
Depreciation and amortization			269.1				272.6
Change in inventories			58.1				(56.2	)
Total operating costs (b)			1,487.9				922.3
Uranium produced & purchased (million lbs) (c)			40.9				30.4
Cash costs per pound (a ÷ c)			28.38				23.22
Total costs per pound (b ÷ c)			36.38				30.34

URANIUM SEGMENT OUTLOOK

We expect to produce 30.0 million pounds in 2016 and have commitments under long-term contracts to purchase approximately 9 million pounds.

Based on the contracts we have in place, and not including sales between our segments, we expect to deliver between 30 million and 32 million pounds of U₃O₈ in 2016. We expect the unit cost of sales to be up to 5% higher than in 2015, primarily due to the planned purchases during the year. If we make additional discretionary purchases in 2016 at a cost different than our other sources of supply, then we expect the overall unit cost of sales to be affected.

We expect revenue to be up to 5% lower than in 2015 as a result of an expected decrease in deliveries, not including sales between our segments, partially offset by a higher average realized price.

ROYALTIES

We pay royalties on the sale of all uranium extracted at our mines in the province of Saskatchewan. Two types of royalties are paid:

 

•

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

 

•

Profit royalty: a 10% royalty is charged on profit up to and including $22.70/kg U3O8 ($10.30/lb) and a 15% royalty is charged on profit in excess of $22.70/kg U3O8. Profit is determined as revenue less certain operating, exploration, reclamation and capital costs. Both exploration and capital costs are deductible at the discretion of the producer.

As a resource corporation in Saskatchewan, we also pay a corporate resource surcharge of 3% of the value of resource sales.

 

44    CAMECO CORPORATION

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During the period from 2013 to 2015, transitional rules for the new profit royalty regime were applied whereby only 50% of capital costs were deductible. The remaining 50% was accumulated and will now be deductible beginning in 2016. In addition, the capital allowance related to Cigar Lake under the previous system was grandfathered and is also now deductible beginning in 2016. Based on the expected application of transitional and grandfathered capital allowance deductions, we anticipate that only the first tier of the profit royalty (10%) will apply in 2016 and 2017. As capital pools are depleted, we expect to also be subject to the top tier of the profit royalty (15%) in 2018.

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

 

HIGHLIGHTS				2015				2014				CHANGE
Production volume (million kgU)					9.7				11.6				(16	)%
Sales volume (million kgU)1					13.6				15.5				(12	)%
Average realized price		($Cdn/kgU)			23.37				19.70				19	%
Average unit cost of sales (including D&A)		($Cdn/kgU)			18.87				17.24				9	%
Revenue ($ millions)1					319				306				4	%
Gross profit ($ millions)					61				38				61	%
Gross profit (%)					19				12				58	%

 

1	Includes sales and revenue between our uranium, fuel services and NUKEM segments (339,000 kgU in sales and revenue of $2.9 million in 2015, 0.5 million kgU in sales and revenue of $4 million in 2014).

Total revenue increased by 4% due to a 19% increase in the realized price, partially offset by a 12% decrease in sales volumes.

The total cost of products and services sold (including D&A) decreased by 4% compared to 2014 ($258 million compared to $268 million in 2014), as a 12% decrease in sales volumes was partially offset by a 9% increase in the average unit cost of sales (including D&A). When compared to 2014, the average unit cost of sales was 9% higher due to the mix of fuel services products sold.

The net effect was a $23 million increase in gross profit.

FUEL SERVICES OUTLOOK

In 2016, we plan to produce 8 million to 9 million kgU, and we expect sales volumes, not including intersegment sales, to be up to 5% lower than in 2015. Overall revenue is expected to increase by up to 5% as lower sales volumes will be more than offset by an increase in the average realized price. We expect the average unit cost of sales (including D&A) to increase by 10% to 15%; therefore, overall gross profit will decrease as a result.

NUKEM

 

HIGHLIGHTS				2015				2014				CHANGE
Sales volume U3O8 (million lbs)1					10.7				8.1				32	%
Average realized price		($Cdn/lb)			48.82				44.90				9	%
Cost of product sold (including D&A)					512				327				57	%
Revenue ($ millions)1					554				349				59	%
Gross profit ($ millions)					42				22				91	%
Gross profit (%)					8				6				33	%

 

1	Includes sales and revenue between our uranium, fuel services and NUKEM segments (0.9 million pounds in sales and revenue of $19.3 million in 2015, 1.1 million pounds in sales and revenue of $43 million in 2014).

During 2015, NUKEM delivered 10.7 million pounds of uranium, an increase of 2.6 million pounds compared to the previous year due to an increase in market activity. Revenues from NUKEM amounted to $554 million, 59% higher than in 2014 as a result of higher sales volumes and an increase in the average realized price, mainly due to weakening of the Canadian dollar. Gross profit percentage was 8% for 2015, compared to 6% for 2014.

The net effect was a $20 million increase in gross profit.

NUKEM OUTLOOK

For 2016, NUKEM expects to deliver between 9 million and 10 million pounds of uranium. Total revenue and unit cost of sales, not including intersegment sales, is expected to increase by 5% to 10% compared to 2015; however, the overall gross profit percentage is expected to be slightly lower than 2015 at 4% to 5%.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    45

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Fourth quarter financial results

Consolidated results

 

		THREE MONTHS ENDED
HIGHLIGHTS		DECEMBER 31
($ MILLIONS EXCEPT WHERE INDICATED)		2015				2014				CHANGE
Revenue			975				889				10	%
Gross profit			282				251				12	%
Net earnings (loss) attributable to equity holders			(10	)			73				(114	)%
$ per common share (basic)			(0.03	)			0.18				(114	)%
$ per common share (diluted)			(0.03	)			0.18				(114	)%
Adjusted net earnings (non-IFRS, see page 25)			151				205				(26	)%
$ per common share (adjusted and diluted)			0.38				0.52				(27	)%
Cash provided by operations (after working capital changes)			503				236				113	%

NET EARNINGS

In the fourth quarter of 2015, our net loss was $10 million ($(0.03) per share diluted), a decrease of $83 million compared to net earnings of $73 million ($0.18 per share diluted) in 2014, mainly due to:

 

•

greater losses on foreign exchange derivatives resulting from the weakening of the Canadian dollar

 

•

lower income tax recovery due to the reduction of our deferred tax asset in the US

 

•

higher impairment charges in 2015 ($210 million in 2015, $131 million in 2014)

partially offset by:

 

•

higher uranium gross profits resulting mainly from a higher average realized price and higher sales volumes

 

•

higher gross profits from our fuel services segment due to a higher average realized price

 

•

lower exploration expenditures

 

•

the reduction of our provision related to the CRA litigation

In addition, in the fourth quarter of 2014 there was a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher net earnings in the fourth quarter of 2014 compared to the same period in 2015. The impact of the settlement was partially offset by the write-off of $41 million of assets under construction as a result of changes made to the scope of a number of projects in the fourth quarter of 2014.

ADJUSTED NET EARNINGS

On an adjusted basis, our earnings this quarter were $151 million ($0.38 per share diluted) compared to $205 million ($0.52 per share diluted) (non-IFRS measure, see page 25) in 2014, mainly due to:

 

•

a lower income tax recovery primarily due to the reduction of our deferred tax asset in the US

partially offset by:

 

•

higher uranium gross profits resulting mainly from a higher average realized price and higher sales volumes

 

•

higher gross profits from our fuel services segment mainly due to a higher average realized price

 

•

lower exploration expenditures

 

•

the reduction of our provision related to the CRA litigation

In addition, in the fourth quarter of 2014 there was a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer that contributed to the higher adjusted net earnings in the fourth quarter of 2014 compared to the same period in 2015.

 

46    CAMECO CORPORATION

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We use adjusted net earnings, a non-IFRS measure, as a more meaningful way to compare our financial performance from period to period. See page 25 for more information. The following table reconciles adjusted net earnings with our net earnings.

 

		THREE MONTHS ENDED DECEMBER 31
($ MILLIONS)		2015				2014
Net earnings (loss) attributable to equity holders			(10	)			73
Adjustments
Adjustments on derivatives (pre-tax)			10				10
NUKEM purchase price inventory recovery			—				(4	)
Impairment charges			210				131
Income taxes on adjustments			(59	)			(46	)
Write-off of assets			—				41
Adjusted net earnings			151				205

ADMINISTRATION

 

		THREE MONTHS ENDED DECEMBER 31
($ MILLIONS)		2015				2014				CHANGE
Direct administration			51				52				(2	)%
Stock-based compensation			4				3				33	%
Total administration			55				55				—

Direct administration costs were $51 million in the quarter, $1 million lower than the same period last year due to the timing of expenditures, partially offset by higher legal costs as our CRA dispute progresses toward trial. Stock-based compensation expenses were $1 million higher than the fourth quarter of 2014. See note 25 to the financial statements.

Quarterly trends

 

HIGHLIGHTS		2015																2014
($ MILLIONS EXCEPT PER SHARE AMOUNTS)		Q4				Q3				Q2				Q1				Q4				Q3				Q2				Q1
Revenue			975				649				565				566				889				587				502				419
Net earnings (loss) attributable to equity holders			(10	)			(4	)			88				(9	)			73				(146	)			127				131
$ per common share (basic)			(0.03	)			(0.01	)			0.22				(0.02	)			0.18				(0.37	)			0.32				0.33
$ per common share (diluted)			(0.03	)			(0.01	)			0.22				(0.02	)			0.18				(0.37	)			0.32				0.33
Adjusted net earnings (non-IFRS, see page 25)			151				78				46				69				205				93				79				36
$ per common share (adjusted and diluted)			0.38				0.20				0.12				0.18				0.52				0.23				0.20				0.09
Earnings (loss) from continuing operations			(10	)			(4	)			88				(10	)			72				(146	)			127				4
$ per common share (basic)			(0.03	)			(0.01	)			0.22				(0.02	)			0.18				(0.37	)			0.18				0.01
$ per common share (diluted)			(0.03	)			(0.01	)			0.22				(0.02	)			0.18				(0.37	)			0.18				0.01
Cash provided by continuing operations (after working capital changes)			503				(121	)			(65	)			134				236				263				(25	)			7

Key things to note:

 

•

Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 70% of consolidated revenues in the fourth quarter of 2015 and 68% of consolidated revenues in the fourth quarter of 2014.

 

•

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 25 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    47

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Fourth quarter financial results by segment

Uranium

 

				THREE MONTHS ENDED DECEMBER 31
HIGHLIGHTS				2015				2014				CHANGE
Production volume (million lbs)					9.6				8.2				17	%
Sales volume (million lbs)1					11.2				10.7				5	%
Average spot price		($US/lb)			35.45				37.13				(5	)%
Average long-term price		($US/lb)			44.00				48.00				(8	)%
Average realized price		($US/lb)			46.36				50.57				(8	)%
		($Cdn/lb)			61.24				56.78				8	%
Average unit cost of sales (including D&A)		($Cdn/lb)			38.25				34.27				12	%
Revenue ($ millions)1					687				606				13	%
Gross profit ($ millions)					257				240				7	%
Gross profit (%)					37				40				(8	)%

 

1	Includes sales and revenue between our uranium, fuel services and NUKEM segments (17,000 pounds in sales and revenue of $0.5 million in Q4 2015, 400,000 pounds in sales and revenue of $15 million in Q4 2014).

Production volumes this quarter were 17% higher compared to the fourth quarter of 2014, mainly as a result of higher production from the rampup of Cigar Lake production, offset by lower production at McArthur River/Key Lake, Rabbit Lake and our US ISR operations. See Uranium – production overview on page 54 for more information.

Uranium revenues were up 13% due to a 5% increase in sales volumes, which represents normal quarterly variance in our delivery schedule, and an 8% increase in the average realized price.

Average spot and long-term prices decreased, as did our US dollar average realized price due to lower prices under fixed-price contracts, and the mix of market and fixed contracts. However, the effect of foreign exchange resulted in an 8% higher Canadian dollar average realized price than the prior year. In the fourth quarter of 2015, our realized foreign exchange rate was $1.32 compared to $1.12 in the prior year.

Total cost of sales (including D&A) increased by 17% ($429 million compared to $366 million in 2014). This was the result of a 12% increase in the average unit cost of sales and a 5% increase in sales volumes.

The unit cost of sales increased due to an increase in the volume of material purchased throughout the year at prices higher than our average cost of inventory and an increase in the unit production costs related to the addition of higher cost production from Cigar Lake during rampup.

The net effect was a $17 million increase in gross profit for the quarter.

 

48    CAMECO CORPORATION

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

 

		THREE MONTHS ENDED DECEMBER 31
($/LB)		2015				2014				CHANGE
Produced
Cash cost			16.04				14.19				13	%
Non-cash cost			10.96				7.15				53	%
Total production cost			27.00				21.34				27	%
Quantity produced (million lbs)			9.6				8.2				17	%
Purchased
Cash cost1			43.65				39.03				12	%
Quantity purchased (million lbs)			3.2				3.7				(14	)%
Totals
Produced and purchased costs1			31.16				26.84				16	%
Quantities produced and purchased (million lbs)			12.8				11.9				8	%

 

1

In the fourth quarter of 2015, cash costs of purchased material were $33.79 (US) per pound compared to $35.05 (US) per pound in the same period in 2014. In the fourth quarter of 2015, the exchange rate on purchases averaged $1.00 (US) for $1.29 (Cdn) compared to $1.00 (US) for $1.11 (Cdn) during the same period in 2014.

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 2015 and 2014.

CASH AND TOTAL COST PER POUND RECONCILIATION

 

		THREE MONTHS ENDED DECEMBER 31
($ MILLIONS)		2015				2014
Cost of product sold			328.3				269.0
Add / (subtract)
Royalties			(49.5	)			(34.5	)
Other selling costs			(6.7	)			(2.3	)
Change in inventories			21.5				28.5
Cash operating costs (a)			293.6				260.7
Add / (subtract)
Depreciation and amortization			100.9				96.7
Change in inventories			4.3				(38.0	)
Total operating costs (b)			398.8				319.4
Uranium produced & purchased (million lbs) (c)			12.8				11.9
Cash costs per pound (a ÷ c)			22.94				21.91
Total costs per pound (b ÷ c)			31.16				26.84

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    49

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Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

 

				THREE MONTHS ENDED DECEMBER 31
HIGHLIGHTS				2015				2014				CHANGE
Production volume (million kgU)					3.4				2.7				26	%
Sales volume (million kgU)1					4.5				7.4				(39	)%
Average realized price		($Cdn/kgU)			21.88				16.92				29	%
Average unit cost of sales (including D&A)		($Cdn/kgU)			17.18				14.78				16	%
Revenue ($ millions)1					99				125				(21	)%
Gross profit ($ millions)					21				16				31	%
Gross profit (%)					21				13				62	%

 

1	Includes sales and revenue between our uranium, fuel services and NUKEM segments (339,000 kgU in sales and revenue of $2.9 million in Q4 2015, 0.5 million kgU in sales and revenue of $4 million in Q4 2014).

Total revenue decreased by 21% due to a 39% decrease in sales volumes, partially offset by a 29% increase in average realized price.

The total cost of sales (including D&A) decreased by 28% ($78 million compared to $109 million in the fourth quarter of 2014) mainly due to a 39% decrease in sales volumes, partially offset by an increase of 16% in the average unit cost of sales, primarily as a result of the mix of products sold.

The net effect was a $5 million increase in gross profit.

NUKEM

 

				THREE MONTHS ENDED DECEMBER 31
HIGHLIGHTS				2015				2014				CHANGE
Sales volume U3O8 (million lbs)1					3.7				3.4				9	%
Average realized price		($Cdn/lb)			52.22				52.12				—
Cost of product sold (including D&A)					186				156				19	%
Revenue ($ millions)1					192				159				21	%
Gross profit ($ millions)					6				3				100	%
Gross profit (%)					3				2				50	%

 

1	Includes sales and revenue between our uranium, fuel services and NUKEM segments (nil in Q4 2015, 1.1 million pounds in sales and revenue of $43 million in Q4 2014).

NUKEM delivered 3.7 million pounds of uranium, an increase of 0.3 million pounds compared to 2014. NUKEM revenues amounted to $192 million compared to $159 million in 2014 due to an increase in volumes delivered.

Gross profit percentage was 3% in the fourth quarter of 2015, compared to 2% in the fourth quarter of 2014.

The net effect was a $3 million increase in gross profit.

 

50    CAMECO CORPORATION

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Our operations and projects

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

 

52		MANAGING THE RISKS
54		URANIUM – PRODUCTION OVERVIEW
54		PRODUCTION OUTLOOK
55		URANIUM – OPERATING PROPERTIES
55		MCARTHUR RIVER MINE / KEY LAKE MILL
60		CIGAR LAKE
65		INKAI
68		RABBIT LAKE
70		SMITH RANCH-HIGHLAND
71		CROW BUTTE
72		URANIUM – PROJECTS UNDER EVALUATION
72		MILLENNIUM
72		YEELIRRIE
72		KINTYRE
74		URANIUM – EXPLORATION AND CORPORATE DEVELOPMENT
76		FUEL SERVICES
76		BLIND RIVER REFINERY
77		PORT HOPE CONVERSION SERVICES
77		CAMECO FUEL MANUFACTURING INC. (CFM)
79		NUKEM GMBH

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    51

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Managing the risks

The nature of our operations means we face many potential risks and hazards that could have a significant impact on our business. Our risk policy and process involves a broad, systematic approach to identifying, assessing, reporting and managing the significant risks we face in our business and operations. The policy establishes clear accountabilities for enterprise risk management. We use a common risk matrix throughout the company and consider any risk that has the potential to significantly affect our ability to achieve our corporate objectives or strategic plan as an enterprise risk. However, there is no assurance we will be successful in preventing the harm any of these risks and hazards could cause. We recommend you read our most recent management proxy circular for more information about our risk oversight.

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

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

Regulatory risks

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

Environment Canada has been reviewing the Metal Mining Effluent Regulations (MMER). This review could result in new limits for existing MMER substances and proposed limits for new substances that could impact our Saskatchewan operations.

 

•

The U.S. Environmental Protection Agency is proposing to add new health and environmental protection standards to regulate byproduct materials produced by uranium in situ recovery operations. The proposed rule includes surface and subsurface standards, with a primary focus on groundwater protection, restoration and stability. Particularly concerning is the proposed requirement that groundwater must be monitored for 30 years after restoration.

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.

 

52    CAMECO CORPORATION

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

At the end of 2015, our estimate of total decommissioning and reclamation costs was $975 million. This is the undiscounted value of the obligation and is based on our current operations. We had accounting provisions of $917 million at the end of 2015 (the present value of the $975 million). Since we expect to incur most of these expenditures at the end of the useful lives of the operations they relate to, our expected costs for decommissioning and reclamation for the next five years are not material.

We provide financial assurances for decommissioning and reclamation such as letters of credit to regulatory authorities, as required. We had a total of $1 billion in letters of credit supporting our reclamation liabilities at the end of 2015. All of our North American operations have letters of credit in place that provide financial assurance in connection with our preliminary plans for decommissioning of 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 2015, we invested:

 

•

$77 million in environmental protection, monitoring and assessment programs, about the same as 2014

 

•

$31 million in health and safety programs, or 29% more than 2014 as a result of ventilation improvements at McArthur River

Spending on environmental programs is expected to increase slightly in 2016, while spending on health and safety programs will decrease toward 2014 levels.

Operational risks

Other operational risks and hazards include:

 

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    53

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Uranium – production overview

Production in our uranium segment in the fourth quarter was 9.6 million pounds, 17% higher compared to the same period in 2014 primarily due to the rampup of production at Cigar Lake. Production for the year was 28.4 million pounds, 22% higher than in 2014. See Uranium - operating properties starting on page 55 for more information.

Uranium production

 

CAMECO SHARE		THREE MONTHS ENDED DECEMBER 31								YEAR ENDED DECEMBER 31
(MILLION LBS)		2015				2014				2015				2014				2015 PLAN1				2016 PLAN
McArthur River/Key Lake			3.8				4.4				13.3				13.3				13.7				14.0
Cigar Lake			2.3				0.2				5.7				0.2				4.0 - 5.0				8.0	2
Inkai			1.1				0.7				3.4				2.9				3.0				3.0
Rabbit Lake			2.0				2.1				4.2				4.2				3.9				3.6
Smith Ranch-Highland			0.3				0.6				1.4				2.1				1.4				1.2
Crow Butte			0.1				0.2				0.4				0.6				0.3				0.2
Total			9.6				8.2				28.4				23.3				26.3 - 27.3				30.0	2

 

1	We updated our initial 2015 plan for Cigar Lake (to 5 million pounds, from between 3 and 4 million pounds) in our Q3 MD&A.

2	Our 2016 plan for packaged production from Cigar Lake is subject to regulatory approval for an annual production limit increase at the McClean Lake mill. See Uranium – operating properties – Cigar Lake starting on page 60 for more information.

Production Outlook

We remain focused on taking advantage of the long-term growth we see coming in our industry, while maintaining the ability to respond to market conditions as they evolve. Our strategy is to focus on our tier-one assets and profitably produce at a pace aligned with market signals in order to increase long-term shareholder value.

We plan to:

 

•

ensure continued safe, reliable, low-cost production from our tier-one assets – McArthur River/Key Lake, Cigar Lake and Inkai

 

•

complete rampup of production at Cigar Lake

 

•

seek to expand production at McArthur River/Key Lake in conjunction with market signals

 

•

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

 

•

maintain our low-cost advantage by focusing on execution and operational excellence

 

54    CAMECO CORPORATION

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Uranium – operating properties

McArthur River mine / Key Lake mill

 

		2015 Production (our share) 13.3M lbs 2016 Production Outlook (our share) 14.0M lbs Estimated Reserves (our share) 234.9M lbs Estimated Mine Life 2033

McArthur River is the world’s largest, high-grade uranium mine, and Key Lake is the world’s largest uranium mill.

Ore grades at the McArthur River mine are 100 times the world average, which means it can produce more than 19 million pounds per year by mining only 150 to 200 tonnes of ore per day. We are the operator of both the mine and mill.

McArthur River is one of our three material uranium properties.

 

Location		Saskatchewan, Canada
Ownership		McArthur River – 69.805%
		Key Lake – 83.33%
Mine type		Underground
Mining methods		Primary: raiseboring
		Secondary: blasthole stoping, boxhole boring
End product		Uranium concentrates
Certification		ISO 14001 certified
Estimated reserves		234.9 million pounds (proven and probable), average grade U3O8: 10.94%
Estimated resources		3.9 million pounds (measured and indicated), average grade U3O8: 3.77%
		40.9 million pounds (inferred), average grade U3O8: 7.72%
Licensed capacity		Mine and mill: 25.0 million pounds per year
Licence term		Through October, 2023
Total production: 2000 to 2015		291.1 million pounds (McArthur River/Key Lake) (100% basis)
1983 to 2002		209.8 million pounds (Key Lake) (100% basis)
2015 production		13.3 million pounds (19.1 million pounds on 100% basis)
2016 production outlook		14.0 million pounds (20.0 million pounds on 100% basis)
Estimated decommissioning cost		$48 million – McArthur River (100% basis)
		$218 million – Key Lake (100% basis)

All values shown, including reserves and resources, represent our share only, unless indicated.

BACKGROUND

Mining methods and techniques

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

Ground freezing

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    55

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Raisebore mining

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

 

•

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

 

•

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

 

•

once mining is complete, filling each raisebore hole with concrete

 

•

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

 

•

starting the process again with the next raisebore chamber

 

McArthur River currently has six areas with delineated mineral reserves and delineated mineral resources (zones 1 to 4, zone 4 south and zone B) and two additional areas with delineated mineral resources (zone A, McArthur north). We are currently mining zone 2 and zone 4.

Zone 2 has been actively mined since production began. It is divided into four panels (panels 1, 2, 3 and 5) based on the configuration of the freezewall around the ore. As the freezewall is expanded, the inner connecting freezewalls are decommissioned in order to recover the uranium that was inaccessible around the active freeze pipes. Panel 5 represents the upper portion of zone 2, overlying part of the other panels. 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 and north areas.

The Canadian Nuclear Safety Commission (CNSC) has granted approval for the use of two secondary extraction methods: blasthole stoping and boxhole boring.

Our use of blasthole stoping as an ore extraction method has increased as a result of the significant productivity improvements we have achieved with this method. The amount of ore extracted from a single stope can be equivalent to four to eight raisebore holes, resulting in more efficient mining, less waste rock handling, less backfill placement and lower backfill dilution in the ore shipped to Key Lake.

We have used the approved mining methods to successfully extract over 290 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, although we now expect to mine a significant portion of the remaining reserves with blasthole stoping.

 

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Blasthole stoping

Similar to raiseboring, blasthole stoping requires establishing drill access above the mineralization and extraction access below the mineralization. We begin each stope with a single raisebore hole (explained above). The stope is then formed by expanding the circumference of the raise by drilling longholes around the raisebore hole and blasting the ore. The blasted material funnels into the raisebore hole and drops to the extraction level below. The broken rock is collected on the lower level and removed by line-of-sight remote-controlled scoop trams, then transported to the grinding circuit. Once a stope is mined out, it is backfilled with concrete to maintain ground stability and allow the next stope and/or raise to be mined. This mining method has been used extensively in the mining industry, including uranium mining.

We continue to employ blasthole stoping only in areas where the longholes can be accurately drilled, and where stable stopes can be excavated without jeopardizing the integrity of the freezewall.

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.

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.

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.

2015 UPDATE

Production

Production from McArthur River/Key Lake was 19.1 million pounds; our share was 13.3 million pounds. This was 3% lower than our forecast for the year due to unplanned maintenance outages to repair the calciner at Key Lake. Annual production was unchanged from 2014.

Licensing and production capacity

In 2015, the CNSC approved our application to increase McArthur River’s licensed annual production to 25 million pounds (100% basis) to allow flexibility to match the approved Key Lake mill capacity. The licence conditions handbooks for these operations now allow both operations to produce up to 25 million pounds (100% basis) per year.

Key Lake extension and McArthur River production expansion

In support of our strategy to maintain the flexibility to respond to market conditions as they evolve, we continue to advance projects that are necessary to sustain and increase production when the market signals that additional production is needed.

 

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The Key Lake mill began operating in 1983 and we continue to upgrade circuits with new technology to simplify operations and improve environmental performance. The extension project involved increasing our tailings capacity and the mill’s nominal annual production rate to closely follow production from the McArthur River mine. As part of the mill upgrades, we continue to construct and commission a new calciner circuit, and expect to begin operating with the new calciner in 2016. The existing calciner circuit will remain in place until operational reliability of the new calciner is achieved. The calciner replacement project was planned in a way that temporarily allows us to use either calciner, which will help to mitigate risks to our production rate during the commissioning phase. In order to increase production at Key Lake, we also need to optimize and expand the solvent extraction and crystallization circuits in the mill (projects planned for 2017).

At McArthur River, we must continue to successfully transition into new mine areas through mine development and investment in support infrastructure. We plan to:

 

•

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

 

•

expand the concrete distribution systems and batch plant capacity

New mining areas

New mining zones and increased mine production require increased freeze capacity and ventilation. In 2015, we continued to upgrade our electrical infrastructure on surface as part of our plan to address these future needs. We advanced groundworks to prepare for the next freeze plant, which is scheduled to begin freezing the south end of the orebody (zone 4) in 2017.

We also made changes in shaft 2 to increase air flow, resulting in a 15% to 20% improvement in ventilation capacity. The improved ventilation eliminates the need for a new ventilation shaft to support a higher production rate.

Tailings capacity

We expect to have sufficient tailings capacity to mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

PLANNING FOR THE FUTURE

Production

We plan to produce 20.0 million pounds in 2016; our share is 14.0 million pounds.

Expansion progress

As previously disclosed in our 2012 Technical Report, we plan to reach an annual capacity of 22 million pounds by 2018. The capital required to do so is shown in our 2016 capital spending plan, and in our outlook for investing activities in 2017 and 2018, beginning on page 38.

As we increase to 22 million pounds per year, we will optimize the capacity of both the Key Lake mill and McArthur River mine with a view to further increasing production to 25 million pounds per year (100% basis), as market conditions improve. Using this approach, we do not expect significant additional growth capital will be required to increase from annual production of 22 million pounds to an annual rate of 25 million pounds. We expect that this paced approach will allow us to extract maximum value from the operation as the market transitions.

Exploration

In 2015, underground drilling further delineated the zone A mineral resources. Underground definition drilling of zone B will be conducted in 2016 and 2017 to provide the information required for engineering work to develop more detailed mining plans.

MANAGING OUR RISKS

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

 

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Transition to new mining areas

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

Water inflow risk

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

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

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

 

•

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

 

•

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

 

•

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

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

We also manage the risks listed on pages 52 to 53.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    59

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Uranium – operating properties

Cigar Lake

 

		2015 Production (our share) 5.7M lbs 2016 Production Outlook (our share) 8.0M lbs1 Estimated Reserves (our share) 110.9M lbs Estimated Mine Life 2028

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

Cigar Lake is one of our three material uranium properties.

 

Location		Saskatchewan, Canada
Ownership		50.025%
Mine type		Underground
Mining method		Jet boring system
End product		Uranium concentrates
Certification		ISO 14001 certified
Estimated reserves		110.9 million pounds (proven and probable), average grade U3O8: 16.70%
Estimated resources		1.6 million pounds (measured and indicated), average grade U3O8: 7.38% 51.6 million pounds (inferred), average grade U3O8: 16.43%
Licensed capacity		18.0 million pounds per year (our share 9.0 million pounds per year)
Licence term		Through June, 2021
Total production: 2014 to 2015		11.8 million pounds (100% basis)
2015 production		5.7 million pounds (11.3 million pounds on 100% basis)
2016 production outlook		8.0 million pounds (16.0 million pounds on 100% basis)1
Estimated decommissioning cost		$49 million (100% basis)

 

1	Our 2016 production plan is subject to regulatory approval for a production increase at the McClean Lake mill.

All	values shown, including reserves and resources, represent our share only, unless indicated.

BACKGROUND

Development

We began developing the Cigar Lake underground mine in 2005, but development was delayed due to water inflows. In October 2014, the McClean Lake mill produced first uranium concentrate from ore mined at the Cigar Lake operation. Commercial production was declared in May 2015.

Mining method and development techniques

Bulk freezing

The sandstone that overlays the deposit and basement rocks is water-bearing, with large volumes of water under significant pressure. To prevent water from entering the mine, help stabilize weak rock formations, and meet our production schedule, the ore zone and surrounding ground in the area to be mined must meet specific ground freezing requirements before we begin jet boring.

 

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During construction, development and remediation of the underground infrastructure, we employed a hybrid ground freezing approach using a combination of underground and surface freezing. The costs related to each technique are similar; however, there are significant advantages to freezing the ground from the surface. With surface freezing, less mine development is required, which results in less waste rock and greater ground stability, since freeze tunnels are not required between production tunnels. In addition, congestion is reduced and underground development for freeze infrastructure is no longer a critical path mine activity. Based on these advantages, we have elected to proceed exclusively using surface freezing to mine current reserves at Cigar Lake.

 

Jet boring

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

 

•

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

 

•

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

 

•

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

 

•

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

 

•

starting the process again with the next cavity

Jet boring system (JBS) process

 

 

 

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We have divided the orebody into production panels and at least three production panels need to be frozen at one time to achieve the full annual production rate of 18 million pounds. One JBS machine will be located in each frozen panel and the three JBS machines required are currently in operation. Due to limitations on the availability of high pressure water, two machines can be actively mining at any given time while the third is moving, setting up, or undergoing maintenance. Later in the mine plan, we may require a fourth JBS machine to sustain annual production of 18 million pounds.

Milling

All of Cigar Lake’s ore slurry is being processed at the McClean Lake mill, operated by AREVA. The McClean Lake mill is undergoing modifications and expansion in order to:

 

•

operate at Cigar Lake’s targeted annual production level of 18 million pounds U3O8

 

•

process and package all of Cigar Lake’s current mineral reserves

The Cigar Lake joint venture is paying the capital costs for the modification and expansion.

2015 UPDATE

Production

Total packaged production from Cigar Lake was 11.3 million pounds U₃O₈; our share was 5.7 million pounds. The operation exceeded our forecast of 10 million pounds (100% basis) as a result of higher productivity and our intention to adjust annual production as necessary, based on our operating experience during rampup.

During the year, we:

 

•

completed commissioning of the equipment required to operate three JBS units at a production scale

 

•

brought on additional slurry haul trucks to ensure a sufficient quantity of ore slurry can be transported to the McClean Lake mill

 

•

completed final commissioning of underground processing circuits and updated our production rampup plan based on commissioning experience

 

•

modified mine and project plans to reflect our decision to exclusively freeze from surface

 

•

declared commercial production

Commercial production

Commercial production signals a transition in the accounting treatment for costs incurred at the mine. Cigar Lake met all of the criteria for commercial production, including cycle time and process specifications, in the second quarter of 2015. Therefore, effective May 1, 2015, we began charging all production costs, including depreciation, to inventory and subsequently recognizing them in cost of sales as the product is sold.

Underground development

As a result of our decision to exclusively use surface freezing going forward, and the resulting change in the mine plan, the bulk of the development and freeze drilling required for mining in 2016 is already complete. We are continuing to plan for future expansion of surface freezing infrastructure in late 2016.

McClean Lake mill update

Additional estimated expenditures of $50 million (100% basis, our share $25 million) are expected to be required at the McClean Lake mill in 2016, primarily to complete upgrades in the tailings neutralization area in support of the continued rampup to full production of 18 million pounds per year.

PLANNING FOR THE FUTURE

Production

In 2016, we expect to produce 16.0 million packaged pounds at Cigar Lake; our share is 8.0 million pounds.

 

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In 2016, we also expect to:

 

•

extend the current surface freeze pad and advance planning for freeze plant infrastructure expansion to support future production

 

•

advance underground development according to the new mine plan and backfill drifts no longer required for underground freezing operations

 

•

continue ramping up towards the planned full annual production rate of 18 million pounds (100% basis) in 2017

Exploration

We are planning to conduct delineation drilling from surface to confirm and upgrade resources contained in the western portion of the deposit. Approximately 65,000 metres of diamond drilling is planned over a three-year period, starting in 2016, in order to complete a detailed geological and geotechnical interpretation, a resource estimate, and a technical study for the western portion of the deposit.

Rampup schedule

In 2017, we expect to reach full annual production of 18 million pounds (100% basis, 9 million pounds our share).

The McClean Lake mill’s operating licence currently has an annual production limit of 13 million pounds. AREVA has submitted an application to the CNSC to increase the mill’s licensed annual production limit; our 2016 and 2017 production outlook for Cigar Lake is therefore subject to AREVA securing the regulatory approvals necessary to increase mill production.

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, regulatory approvals, 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.

Limited mining experience of the deposit

Although we have now successfully mined a number of cavities, these may not be representative of the deposit as a whole. As we ramp up production, there may be some technical challenges, which could affect our production plans, including, but not limited to, variable or unanticipated ground conditions, ground movement and cave-ins, water inflows and variable dilution, recovery values, and mining productivity. There is a risk that the rampup to full production may take longer than planned and that the full production rate may not be achieved on a sustained and consistent basis. We are confident we will be able to solve challenges that may arise, but failure to do so would have a significant impact on our business.

Ground freezing

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

Mill modifications

There is a risk to our plan to achieve the full production rate of 18 million pounds per year in 2017 if AREVA is unable to complete and commission the required mill modification and expansion on schedule. We are working closely with AREVA to understand and help mitigate the risks to ensure that mine and mill production schedules are aligned.

Mill licence increase approval

The McClean Lake mill’s current annual operating licence is limited to 13 million pounds. AREVA has submitted an application to the CNSC to increase the mill’s licensed annual production limit to 24 million pounds. There is a risk to our 2016 production plan, and to our plan to achieve the full production rate of 18 million pounds per year in 2017, if AREVA is unable to secure the regulatory approvals necessary to increase mill production.

 

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Labour relations

The current collective agreement between AREVA and unionized employees at the McClean Lake operation expires in May 2016. There is risk to our 2016 and 2017 production outlook for Cigar Lake if AREVA is unable to reach an agreement and there is a labour dispute.

Water inflow risk

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

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

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

 

•

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

 

•

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

 

•

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

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

We also manage the risks listed on pages 52 to 53.

 

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Uranium – operating properties

Inkai

 

		2015 Production (our share) 3.4M lbs 2016 Production Outlook (our share) 3.0M lbs Estimated Reserves (our share) 43.1M lbs Estimated Mine Life 2030 (based on licence term)

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

Inkai is one of our three material uranium properties.

 

Location		South Kazakhstan
Ownership		60%
Mine type		In situ recovery (ISR)
End product		Uranium concentrates
Certifications		BSI OHSAS 18001 ISO 14001 certified
Estimated reserves		43.1 million pounds (proven and probable), average grade U3O8: 0.07%
Estimated resources		30.3 million pounds (indicated), average grade U3O8: 0.08% 144.3 million pounds (inferred), average grade U3O8: 0.05%
Licensed capacity (wellfields)		5.2 million pounds per year (our share 3.0 million pounds per year)
Licence term		Block 1: 2024, Block 2: 2030
Total production: 2009 to 2015		31.8 million pounds (100% basis)
2015 production		3.4 million pounds (5.8 million pounds on 100% basis)
2016 production outlook		3.0 million pounds (5.2 million pounds on 100% basis)
Estimated decommissioning cost (100% basis)		$9 million (US) (100% basis)

All values shown, including reserves and resources, represent our share only, unless indicated.

2015 UPDATE

Production

Total production from Inkai was 5.8 million pounds; our share was 3.4 million pounds. Production was 17% higher than our production in 2014. During 2015, the subsoil use law in Kazakhstan was amended to allow producers to produce within 20% (above or below) their licensed capacity in a year. As a result, Inkai produced 5.8 million pounds in 2015, 11% higher than its licensed capacity. The increase in production was the result of a higher head grade and an increase in wellfield development efficiency compared to 2014.

Project funding

As of December 31, 2015, Inkai had fully repaid the outstanding loan under our agreement to fund its project development costs related to blocks 1 and 2. In 2015, Inkai paid the remaining $0.8 million (US) in interest on the loan and repaid $55 million (US) of principal.

 

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We are currently advancing funds for Inkai’s work on block 3 and, as of December 31, 2015, the principal amounted to $148 million (US). Under the loan agreement, Inkai is to repay Cameco from the net sales proceeds from the sale of production from block 3.

Production expansion

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

 

•

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

 

•

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

Kazatomprom is pursuing a strategic objective to develop uranium processing capacity in Kazakhstan to complement its leading uranium mining operations. Their primary focus is now on uranium refining, which is an intermediate step in the uranium conversion process. A Nuclear Co-operation Agreement between Canada and Kazakhstan is in place, providing the international framework necessary for applying to the two governments for the required licences and permits. We expect to pursue further expansion of production at Inkai at a pace measured to market opportunities. Discussions continue with Kazatomprom.

Block 3 exploration

In 2015, Inkai completed construction of the test leach facility and began pilot production from test wellfields, as well as advancing work on a preliminary appraisal of the mineral potential of block 3 according to Kazakhstan standards.

PLANNING FOR THE FUTURE

Production

We expect total production from blocks 1 and 2 to be 5.2 million pounds in 2016; our share is 3.0 million pounds. We expect to maintain production at this level until the potential growth plans are finalized with Kazatomprom.

Block 3 exploration

In 2016, Inkai expects to continue with pilot production from the test leach facility and to continue working on a final appraisal of the mineral potential according to Kazakhstan standards.

MANAGING OUR RISKS

Block 3 licence extension

The block 3 test leach facility is now operational and state commissioning of the test wellfields was accomplished during 2015. Our application for an extension of the block 3 evaluation period is still pending final approval from the Ministry of Energy of the Republic of Kazakhstan. Inkai continues working on the final appraisal of the mineral potential of block 3 according to Kazakhstan standards. Although a number of extensions of the licence term have been granted by Kazakh regulatory authorities in the past, there is no assurance that a further extension will be granted. Without such extension, there is a risk we could lose our rights to block 3, and a risk we will not be compensated for the funds we advanced to Inkai to fund block 3 activities.

Political risk

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

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

 

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

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

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

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

We also manage the risks listed on pages 52 to 53.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    67

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Uranium – operating properties

Rabbit Lake

 

		2015 Production 4.2M lbs 2016 Production Outlook 3.6M lbs Estimated Reserves 11.9M lbs

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		11.9 million pounds (proven and probable), average grade U3O8: 0.59%
Estimated resources		26.7 million pounds (indicated), average grade U3O8: 0.86%
		33.7 million pounds (inferred), average grade U3O8: 0.58%
Mining methods		Vertical blasthole stoping
Licensed capacity		Mill: maximum 16.9 million pounds per year; currently 11 million
Licence term		Through October, 2023
Total production: 1975 to 2015		202.2 million pounds
2015 production		4.2 million pounds
2016 production outlook		3.6 million pounds
Estimated decommissioning cost		$203 million

2015 UPDATE

Production

Production this year was unchanged from our 2014 production as a result of planned timing of production stopes, coupled with slightly improved ore grades.

Development and production continued at the Eagle Point mine. At the mill, we continued to improve the efficiency of the mill operation schedule.

Temporary mining restrictions

On December 17, 2015, we announced that underground mining activities at Eagle Point were being restricted due to a rock fall in an inactive area of the mine. As a precautionary measure, non-essential personnel were removed from the mine while the condition of the affected area was evaluated. Mine production was suspended, although milling of previously mined and transported ore continued through to year end.

The assessment determined that repairs were necessary to support the ground in the affected area of the mine. The repairs were completed, along with some further assessment of stability in other areas of the mine. The mine was reopened and normal operations resumed on February 3, 2016.

 

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Impairment

During the fourth quarter of 2015, we recognized a $210 million impairment charge related to our Rabbit Lake operation. The impairment was due to increased uncertainty around future production sources for the Rabbit Lake mill as a result of the ongoing economic conditions. The amount of the charge was determined as the excess of carrying value over the recoverable amount. The recoverable amount of the mill was determined to be $69 million.

PLANNING FOR THE FUTURE

Production

We expect to produce 3.6 million pounds in 2016. The decrease compared to 2015 is the result of the restriction of mining activities at the end of 2015, which extended into 2016.

Tailings capacity

Under our current licence, we expect to have sufficient tailings capacity to support milling of Eagle Point ore until about late 2017, based upon expected ore tonnage, milling rates and tailings properties.

Our plan for fully utilizing the available tailings capacity of the Rabbit Lake In-Pit Tailings Management facility requires regulatory approval in 2016 for which we have submitted the required applications. With these regulatory approvals and after we complete the necessary work on the existing pit, we expect to then have sufficient tailings capacity to support milling of Eagle Point ore until at least 2021 based upon expected ore tonnage, milling rates, and tailings properties.

Exploration

We plan to continue our underground drilling reserve replacement program in areas of interest north and northeast of the current mine workings in 2016. The drilling will be carried out from underground locations.

Reclamation

As part of our multi-year site-wide reclamation plan, we spent over $0.7 million in 2015 to reclaim facilities that are no longer in use and plan to spend over $0.5 million in 2016.

MANAGING OUR RISKS

We manage the risks listed on pages 52 to 53.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    69

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Uranium – operating properties

Smith Ranch-Highland & Satellite Facilities

 

		2015 Production 1.4M lbs 2016 Production Outlook 1.2M lbs Estimated Reserves 8.0M lbs

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:		6.2 million pounds (proven and probable), average grade U3O8: 0.09%
		North Butte-Brown Ranch:		1.8 million pounds (proven and probable), average grade U3O8: 0.08%
Estimated resources		Smith Ranch-Highland:		19.8 million pounds (measured and indicated), average grade U3O8: 0.06%
				7.7 million pounds (inferred), average grade U3O8: 0.05%
		North Butte-Brown Ranch		8.8 million pounds (measured and indicated), average grade U3O8: 0.07%
				0.4 million pounds (inferred), average grade U3O8: 0.07%
Mining methods				In situ recovery (ISR)
Licensed capacity				Wellfields: 3 million pounds per year
				Processing plants: 5.5 million pounds per year, including Highland mill
Licence term				Pending renewal – see Production below
Total production: 2002 to 2015				21.8 million pounds
2015 production				1.4 million pounds
2016 production outlook				1.2 million pounds
Estimated decommissioning cost				Smith Ranch-Highland: $206 million (US), North Butte: $22 million (US)

2015 UPDATE

Production

We met our forecast for the year although, as planned, production was 33% lower than in 2014, with new mine units and the North Butte satellite contributing to production at Smith Ranch-Highland in 2015.

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 2016, we expect to produce 1.2 million pounds. The continued decrease is a result of market conditions, which led us to defer some wellfield development.

MANAGING OUR RISKS

We manage the risks listed on pages 52 to 53.

 

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Uranium – operating properties

Crow Butte

 

		2015 Production 0.4M lbs 2016 Production Outlook 0.2M lbs Estimated Reserves 0.7M lbs

Crow Butte was discovered in 1980 and began production in 1991.

 

Location		Nebraska, US
Ownership		100%
End product		Uranium concentrates
ISO certification		ISO 14001 certified
Estimated reserves		0.7 million pounds (proven), average grade U3O8: 0.08%
Estimated resources		15.2 million pounds (measured and indicated), average grade U3O8: 0.25%
		2.9 million pounds (inferred), average grade U3O8: 0.12%
Mining methods		In situ recovery (ISR)
Licensed capacity (processing plants and wellfields)		2.0 million pounds per year
Licence term		Through October, 2024
Total production: 2002 to 2015		10.1 million pounds
2015 production		0.4 million pounds
2016 production outlook		0.2 million pounds
Estimated decommissioning cost		$46 million (US)

2015 UPDATE

Production

Production this year was higher than forecast, but 33% lower than 2014 due to declining head grade.

PLANNING FOR THE FUTURE

Production

In 2016, we expect to produce 0.2 million pounds. The head grade and overall production at Crow Butte is expected to continue to decline, as there are no new wellfields being developed under the current mine plan.

MANAGING OUR RISKS

We manage the risks listed on pages 52 to 53.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    71

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Uranium – projects under evaluation

Work on our projects under evaluation has been scaled back and will continue at a pace aligned with market signals.

Millennium

 

Location		Saskatchewan, Canada
Ownership		69.9%
End product		Uranium concentrates
Potential mine type		Underground
Estimated resources (our share)		53.0 million pounds (indicated), average grade U3O8: 2.39%
		20.2 million pounds (inferred), average grade U3O8: 3.19%

BACKGROUND

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

Yeelirrie

 

Location		Western Australia
Ownership		100%
End product		Uranium concentrates
Potential mine type		Open pit
Estimated resources		127.3 million pounds (measured and indicated), average grade U3O8: 0.16%

BACKGROUND

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

Kintyre

 

Location		Western Australia
Ownership		70%
End product		Uranium concentrates
Potential mine type		Open pit
Estimated resources (our share)		37.5 million pounds (indicated), average grade U3O8: 0.62%
		4.2 million pounds (inferred), average grade U3O8: 0.53%

BACKGROUND

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

2015 PROJECT UPDATES

We believe that we have some of the best undeveloped uranium projects in the world. However, in the current market environment our primary focus is on uranium production and our tier-one assets. We continue to await a signal from the market that additional production is needed prior to making any new development decisions.

This year, on our projects under evaluation we:

 

•

continued studies to assess the technical, environmental and financial aspects of each project

 

•

at Kintyre and at other nearby regional exploration projects, we carried out further exploration work to test for potential satellite deposits. There were no significant results.

 

•

we received environmental approval for Kintyre and continued to advance Yeelirrie through the environmental assessment process

 

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PLANNING FOR THE FUTURE

2016 Planned activity

At Millennium, no work is planned, as regulatory activity related to our final environmental impact statement continues to be on hold. Further progress towards a development decision is not expected until market conditions improve.

At Yeelirrie, we plan to further advance the project through the environmental assessment process and continue working on proposals required under the Yeelirrie State Agreement. Under the State Agreement, the Western Australian Government provides a framework for the approval and development of the project. Detailed proposals for the development of a mine and related infrastructure must be submitted to the government for approval by June 20, 2018, in order to retain the tenements and titles for the Yeelirrie project.

At Kintyre and other nearby regional exploration projects, we expect to continue with further exploration work to test for potential satellite deposits.

MANAGING THE RISKS

For all of our projects under evaluation, we manage the risks listed on pages 52 to 53.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    73

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Uranium – exploration and corporate development

Our exploration program is directed at replacing mineral reserves as they are depleted by our production, and ensuring our future growth. We have maintained an active program even during periods of weak uranium prices, which has helped us secure land with exploration and development prospects that are among the best in the world, mainly in Canada, Australia, Kazakhstan and the US. Globally, our land holdings total 1.6 million hectares (3.9 million acres). In northern Saskatchewan alone, we have direct interests in 600,000 hectares (1.5 million acres) of land covering many of the most prospective exploration areas of the Athabasca Basin. Many of our prospects are located close to our existing operations where we have established infrastructure and capacity to expand.

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

In 2015, we continued our exploration strategy of focusing on the most prospective projects in our portfolio. Exploration is key to ensuring our long-term growth.

 

2015 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 $2 million on four brownfield exploration projects, $4 million on our projects under evaluation in Australia, and $2 million at Inkai and our US operations.

Regional exploration

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

PLANNING FOR THE FUTURE

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

Brownfield exploration

In 2016, we plan to spend approximately $5 million on brownfield exploration and $4 million on projects under evaluation.

Regional exploration

We plan to spend about $36 million on 24 projects in Canada and Australia, the majority of which are at drill target stage. Among the larger expenditures planned is $7 million on the Read Lake project, which is adjacent to McArthur River in Saskatchewan. We will also spend a total of $2 million at Inkai and in the US.

 

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ACQUISITION PROGRAM

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

An acquisition opportunity is never assessed in isolation. Acquisitions must compete for investment capital with our own internal growth opportunities. They are subject to our capital allocation process described in the strategy section, starting on page 14. Currently, given the conditions in the uranium market, and our extensive portfolio of reserves and resources, our focus is on our tier-one assets. We expect that these assets will allow us to meet rising uranium demand with increased production from our best margin operations, and will help to mitigate risk in the event of prolonged uncertainty.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    75

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Fuel services

Refining, conversion and fuel manufacturing

We control about 20% of world UF₆ conversion capacity and are a supplier of natural UO₂. Our focus is on cost-competitiveness and operational efficiency.

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

Blind River Refinery

 

		Licensed Capacity 24.0M kgU of UO3 Licence renewal in Feb, 2022

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		18.0 million kgU as UO3 per year, approved to 24.0 million subject to completion of certain equipment upgrades (advancement depends on market conditions)
Licence term		Through February, 2022
Estimated decommissioning cost		$39 million

 

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Port Hope Conversion Services

 

		Licensed Capacity 12.5M kgU of UF6 2.8M kgU of UO2 Licence renewal in Feb, 2017

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

 

Location		Ontario, Canada
Ownership		100%
End product		UF6, UO2
ISO certification		ISO 14001 certified
Licensed capacity		12.5 million kgU as UF6 per year
		2.8 million kgU as UO2 per year
Licence term		Through February, 2017
Estimated decommissioning cost		$102 million (an updated estimate is currently under regulatory review)

Cameco Fuel Manufacturing Inc. (CFM)

CFM produces fuel bundles and reactor components for CANDU reactors.

 

Location		Ontario, Canada
Ownership		100%
End product		CANDU fuel bundles and components
ISO certification		ISO 9001 certified, ISO 14001 certified
Licensed capacity		1.2 million kgU as UO2 as finished bundles
Licence term		Through February, 2022
Estimated decommissioning cost		$20 million

2015 UPDATE

Production

Fuel services produced 9.7 million kgU, 16% lower than 2014. This was a result of our decision to decrease production in response to weak market conditions and the termination of our toll milling agreement with SFL in 2014.

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

The Vision in Motion project is currently in the feasibility stage and will continue with the CNSC licensing process in 2016, which is required to advance the project.

Labour relations

Approximately 100 unionized employees at Cameco Fuel Manufacturing Inc.’s operations in Port Hope and Cobourg, Ontario accepted a new collective bargaining agreement in the second quarter of 2015. The employees, represented by the United Steelworkers local 14193, agreed to a three-year contract that includes a 7% wage increase over the term of the agreement. The previous contract expired on June 1, 2015.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    77

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PLANNING FOR THE FUTURE

Production

We have decreased our production target for 2016 to between 8 million and 9 million kgU in response to the continued weak market conditions.

Labour relations

The current collective bargaining agreement for our unionized employees at the Port Hope conversion facility expires on June 30, 2016. We will commence the bargaining process in early 2016.

Regulatory

The current operating licence for the Port Hope conversion facility expires in February 2017. The CNSC relicensing process will take place in 2016.

MANAGING OUR RISKS

We also manage the risks listed on pages 52 to 53.

 

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NUKEM GmbH

 

Offices		Alzenau, Germany (Headquarters, NUKEM GmbH)
		Connecticut, US (Subsidiary, NUKEM Inc.)
Ownership		100%
Activity		Trading of uranium and uranium-related products
2015 sales1		10.7 million pounds U3O8
2016 forecast sales		9 to 10 million pounds U3O8

 

1	Includes sales of 0.9 million pounds and revenue of $19.3 million between our uranium, fuel services and NUKEM segments.

BACKGROUND

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

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

NUKEM’s main customers are commercial nuclear power plants using enriched uranium fuel, typically large utilities that are either government owned, or large-scale utilities with multibillion-dollar market capitalizations and strong credit ratings. NUKEM also trades with converters, enrichers, other traders and investors.

NUKEM’s business model

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

MANAGING OUR RISKS

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    79

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Mineral reserves and resources

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

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

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

About mineral resources

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

 

•

Measured and indicated mineral resources can be estimated with sufficient confidence to allow the appropriate application of technical, economic, marketing, legal, environmental, social and governmental factors to support evaluation of the economic viability of the deposit.

 

•

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

 

•

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

 

•

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

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

About mineral reserves

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

 

•

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

 

•

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

We use current geological models, constant dollar average uranium prices of $57 to $59 (US) per pound U₃O₈, and current or projected operating costs and mine plans to estimate our mineral reserves, allowing for dilution and mining losses. We apply our standard data verification process for every estimate.

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

 

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Changes this year

Our share of proven and probable mineral reserves decreased from 429 million pounds U₃O₈ at the end of 2014, to 410 million pounds at the end of 2015. The change was primarily the result of production, which removed 30 million pounds from our mineral inventory. However, the decrease was partially offset due to the replacement of raiseboring with blasthole stoping in some areas of McArthur River, as well as additional information from drilling surface freeze holes at Cigar Lake, which both resulted in higher reserves when the related probable reserves were converted to proven reserves.

Measured and indicated mineral resources decreased from 379 million pounds U₃O₈ at the end of 2014, to 377 million pounds at the end of 2015. Our share of inferred mineral resources is 380 million pounds U₃O₈, an increase of 68 million pounds from the end of 2014. The variance in mineral resources was mainly the result of:

 

•

the addition of 4.5 million pounds U3O8 to indicated resources and 8 million pounds to inferred resources at Rabbit Lake from additional drilling, and from a revision to the equivalent grade formula

 

•

first time reporting for the Fox Lake deposit, on the Read Lake property near McArthur River, adding 53 million pounds U3O8 to inferred resources

 

•

the addition of 13 million pounds U3O8 of inferred resources from the Gryphon deposit on the Wheeler River property

 

•

a revised pit shell defining the mineral resources at Kintyre

Qualified persons

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

 

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    81

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Important information about mineral reserve and resource estimates

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

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

 

•

geological interpretation

 

•

extraction plans

 

•

commodity prices and currency exchange rates

 

•

recovery rates

 

•

operating and capital costs

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

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

Important information for US investors

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

 

•

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

 

•

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

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

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

 

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Mineral reserves

As at December 31, 2015 (100% basis – only the shaded column shows our share)

PROVEN AND PROBABLE

(tonnes in thousands; pounds in millions)

 

				PROVEN												PROBABLE												TOTAL MINERAL RESERVES												OUR RESERVES CONTENT (LBS  U3O8)				METALLURGICAL RECOVERY (%)
PROPERTY		MINING METHOD		TONNES				GRADE % U3O8				CONTENT (LBS U3O8)				TONNES				GRADE % U3O8				CONTENT (LBS U3O8)				TONNES				GRADE % U3O8				CONTENT (LBS U3O8)
McArthur River		UG			1,195.3				9.62				253.5				199.8				18.84				83.0				1,395.1				10.94				336.5				234.9				98.7
Cigar Lake		UG			226.1				21.93				109.3				375.7				13.55				112.3				601.8				16.70				221.6				110.9				98.5
Rabbit Lake		UG			10.6				0.34				0.1				902.9				0.59				11.8				913.5				0.59				11.9				11.9				97.0
Key Lake		OP			61.1				0.52				0.7				—				—				—				61.1				0.52				0.7				0.6				98.7
Inkai		ISR			1,139.5				0.08				2.1				50,476.4				0.07				72.9				51,615.9				0.07				75.0				43.1				85.0
Smith Ranch-Highland		ISR			1,127.8				0.10				2.5				1,871.0				0.09				3.8				2,998.8				0.09				6.2				6.2				80.0
North Butte-Brown Ranch		ISR			644.2				0.08				1.2				373.8				0.08				0.7				1,018.0				0.08				1.8				1.8				60.0
Crow Butte		ISR			412.5				0.08				0.7				—				—				—				412.5				0.08				0.7				0.7				85.0
Total					4,817.2				—				370.1				54,199.5				—				284.4				59,016.7				—				654.5				410.2				—

(UG – underground, OP – open pit, ISR – in situ recovery, totals may not add up due to rounding.

Note that the estimates in the above table:

 

•

use constant dollar average uranium prices of $57 to $59 (US)/lb U3O8

 

•

are based on an average exchange rate of $1.00 US=$1.15 to $1.25 Cdn

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

Metallurgical recovery

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

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    83

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Mineral resources

As at December 31, 2015 (100% – only the shaded columns show our share)

MEASURED, INDICATED AND INFERRED

(tonnes in thousands; pounds in millions)

 

		MEASURED RESOURCES (M)												INDICATED RESOURCES (I)																OUR SHARE TOTAL M+I CONTENT (LBS U3O8)				INFERRED RESOURCES												OUR SHARE INFERRED CONTENT (LBS U3O8)
PROPERTY		TONNES				GRADE % U3O8				CONTENT (LBS U3O8)				TONNES				GRADE % U3O8				CONTENT (LBS U3O8)				TOTAL M+I CONTENT (LBS U3O8)								TONNES				GRADE % U3O8				CONTENT (LBS U3O8)
McArthur River			62.0				3.83				5.2				4.8				3.02				0.3				5.6				3.9				344.2				7.72				58.6				40.9
Cigar Lake			2.7				6.06				0.4				17.5				7.59				2.9				3.3				1.6				284.7				16.43				103.1				51.6
Rabbit Lake			—				—				—				1,402.7				0.86				26.7				26.7				26.7				2,645.6				0.58				33.7				33.7
Millennium			—				—				—				1,442.6				2.39				75.9				75.9				53.0				412.4				3.19				29.0				20.2
Wheeler River			—				—				—				166.4				19.13				70.2				70.2				21.1				842.5				2.38				44.1				13.2
Fox Lake			—				—				—				—				—				—				—				—				386.7				7.99				68.1				53.3
Tamarack			—				—				—				183.8				4.42				17.9				17.9				10.3				45.6				1.02				1.0				0.6
Kintyre			—				—				—				3,897.7				0.62				53.5				53.5				37.5				517.1				0.53				6.0				4.2
Yeelirrie			24,013.5				0.17				92.4				12,626.5				0.13				34.9				127.3				127.3				—				—				—				—
Inkai			—				—				—				31,366.1				0.08				52.6				52.6				30.3				250,958.6				0.05				251.0				144.3
Smith Ranch-Highland			1,241.9				0.11				2.9				14,338.1				0.05				16.9				19.8				19.8				6,861.0				0.05				7.7				7.7
North Butte-Brown Ranch			232.6				0.08				0.4				5,530.3				0.07				8.4				8.8				8.8				294.5				0.07				0.4				0.4
Gas Hills-Peach			687.2				0.11				1.7				3,626.1				0.15				11.6				13.3				13.3				3,307.5				0.08				6.0				6.0
Crow Butte			1,418.2				0.21				6.6				1,354.9				0.29				8.6				15.2				15.2				1,135.2				0.12				2.9				2.9
Ruby Ranch			—				—				—				2,215.3				0.08				4.1				4.1				4.1				56.2				0.14				0.2				0.2
Shirley Basin			89.2				0.16				0.3				1,638.2				0.11				4.1				4.4				4.4				508.0				0.10				1.1				1.1
Total			27,747.4				—				109.9				79,811.2				—				388.7				498.5				377.2				268,599.9				—				613.0				380.5

Totals may not add up due to rounding.

Note that mineral resources:

 

•

do not include amounts that have been identified as mineral reserves

 

•

do not have demonstrated economic viability

 

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Additional information

Due to the nature of our business, we are required to make estimates that affect the amount of assets and liabilities, revenues and expenses, commitments and contingencies we report. We base our estimates on our experience, our best judgment, guidelines established by the Canadian Institute of Mining, Metallurgy and Petroleum and on assumptions we believe are reasonable.

We believe the following critical accounting estimates reflect the more significant judgments used in the preparation of our financial statements. These estimates affect all of our segments, unless otherwise noted.

Decommissioning and reclamation

In our uranium and fuel services segments, we are required to estimate the cost of decommissioning and reclamation for each operation, but we normally do not incur these costs until an asset is nearing the end of its useful life. Regulatory requirements and decommissioning methods could change during that time, making our actual costs different from our estimates. A significant change in these costs or in our mineral reserves could have a material impact on our net earnings and financial position. See note 17 to the financial statements.

Property, plant and equipment

We depreciate property, plant and equipment primarily using the unit-of-production method, where the carrying value is reduced as resources are depleted. A change in our mineral reserves would change our depreciation expenses, and such a change could have a material impact on amounts charged to earnings.

We assess the carrying values of property, plant and equipment and goodwill every year, or more often if necessary. If we determine that we cannot recover the carrying value of an asset or goodwill, we write off the unrecoverable amount against current earnings. We base our assessment of recoverability on assumptions and judgments we make about future prices, production costs, our requirements for sustaining capital and our ability to economically recover mineral reserves. A material change in any of these assumptions could have a significant impact on the potential impairment of these assets.

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

Taxes

When we are preparing our financial statements, we estimate taxes in each jurisdiction we operate in, taking into consideration different tax rates, non-deductible expenses, valuation of deferred tax assets, changes in tax laws and our expectations for future results.

We base our estimates of deferred income taxes on temporary differences between the assets and liabilities we report in our financial statements, and the assets and liabilities determined by the tax laws in the various countries we operate in. We record deferred income taxes in our financial statements based on our estimated future cash flows, which includes estimates of non-deductible expenses. If these estimates are not accurate, there could be a material impact on our net earnings and financial position.

Commencement of production stage

When we determine that a mining property has reached the production stage, capitalization of development ceases, and depreciation of the mining property begins and is charged to earnings. Production is reached when management determines that the mine is able to produce at a consistent or sustainably increasing level. This determination is a matter of judgment. See note 2 to the financial statements for further information on the criteria that we used to make this assessment.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    85

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Purchase price allocations

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

Determination of joint control

We conduct certain operations through joint ownership interests. Judgment is required in assessing whether we have joint control over the investee, which involves determining the relevant activities of the arrangement and whether decisions around relevant activities require unanimous consent. Judgment is also required to determine whether a joint arrangement should be classified as a joint venture or joint operation. Classifying the arrangement requires us to assess our rights and obligations arising from the arrangement. Specifically, management considers the structure of the joint arrangement and whether it is structured through a separate vehicle. When structured through a separate vehicle, we also consider the rights and obligations arising from the legal form of the separate vehicle, the terms of the contractual arrangements and other facts and circumstances, when relevant. This judgment influences whether we equity account or proportionately consolidate our interest in the arrangement.

Controls and procedures

We have evaluated the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2015, as required by the rules of the US Securities and Exchange Commission and the Canadian Securities Administrators.

Management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), supervised and participated in the evaluation, and concluded that our disclosure controls and procedures are effective to provide a reasonable level of assurance that the information we are required to disclose in reports we file or submit under securities laws is recorded, processed, summarized and reported accurately, and within the time periods specified. It should be noted that, while the CEO and CFO believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they do not expect the disclosure controls and procedures or internal control over financial reporting to be capable of preventing all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Management, including our CEO and our CFO, is responsible for establishing and maintaining internal control over financial reporting and conducted an evaluation of the effectiveness of our internal control over financial reporting based on the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2015. We have not made any change to our internal control over financial reporting during the 2015 fiscal year that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

New standards and interpretations not yet adopted

A number of new standards and amendments to existing standards are not yet effective for the year ended December 31, 2015, and have not been applied in preparing these consolidated financial statements. Cameco does not intend to early adopt any of the following amendments to existing standards and does not expect the amendments to have a material impact on the financial statements, unless otherwise noted.

IFRS 15, Revenue from Contracts with Customers (IFRS 15) – In May 2014, the IASB issued IFRS 15 which is effective for periods beginning on or after January 1, 2018 and is to be applied retrospectively. IFRS 15 clarifies the principles for recognizing revenue from contracts with customers. The extent of the impact of adoption of IFRS 15 has not yet been determined.

 

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IFRS 9, Financial Instruments (IFRS 9) – In July 2014, the IASB issued IFRS 9. IFRS 9 replaces the existing guidance in IAS 39, Financial Instruments: Recognition and Measurement (IAS 39). IFRS 9 includes revised guidance on the classification and measurement of financial assets, a new expected credit loss model for calculating impairment on financial assets and new hedge accounting requirements. It also carries forward, from IAS 39, guidance on recognition and derecognition of financial instruments.

IFRS 9 is effective for annual periods beginning on or after January 1, 2018, with early adoption of the new standard permitted. Cameco does not intend to early adopt IFRS 9. The extent of the impact of adoption of IFRS 9 has not yet been determined.

IFRS 16, Leases (IFRS 16) – In January 2016, the IASB issued IFRS 16 which is effective for periods beginning on or after January 1, 2019, with early adoption permitted. IFRS 16 eliminates the current dual model for lessees, which distinguishes between on-balance sheet finance leases and off-balance sheet operating leases. Instead, there is a single, on-balance sheet accounting model that is similar to current finance lease accounting. The extent of the impact of adoption of IFRS 16 has not yet been determined.

 

MANAGEMENT’S DISCUSSION AND ANALYSIS    87