CCO.TO · 2016-02-05

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

Production Results Financials

TSX: CCO website: cameco.com NYSE: CCJ 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			YEAR ENDED
HIGHLIGHTS	DECEMBER 31			DECEMBER 31
($ 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 Uranium ($US/lb) prices ($Cdn/lb) Fuel Services ($Cdn/kgU) NUKEM ($Cdn/lb)	46.36	50.57 (8)% 56.78 8%		45.19	47.53 (5)% 52.37 10%
	61.24			57.58
	21.88	16.92 29%		23.37	19.70 19%
	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.

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
the reduction of our provision related to the CRA litigation
- 2 -

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

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.

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.

2016 FINANCIAL OUTLOOK

	CONSOLIDATED	URANIUM	FUEL SERVICES	NUKEM
	30.0 8 to 9 - - million lbs million kgU
Production
	30 to 32 Decrease 9 to 10 - million lbs2 up to 5% million lbs UO 3 8
Delivery volume1
	Decrease Decrease Increase Increase up to 5% up to 5%4 up to 5% 5% to 10%
Revenue compared to 20153
Average unit cost of sales	Increase Increase - - up to 5%5 10% to 15%
(including D&A)
Direct administration costs	Increase - - - 5% to 10%
compared to 20156
	Gross profit - - - 4% to 5%
Gross profit
Exploration costs compared to	Increase - - - 15% to 20%
2015
	Recovery of - - - 25% to 30%
Tax rate7
	$320 million - - -
Capital expenditures

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.

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 Cigar Lake 10 9 Rabbit Lake 35 33 US ISR 5 7 Inkai 5 1 Fuel services 15 13 Other 5 5
			30
			25
			25
			5
			5
			20
			5
Total sustaining capital 95 84			115
Capacity replacement capital McArthur River/Key Lake 95 96 Cigar Lake 25 26 Rabbit Lake - - US ISR 30 27 Inkai 15 19
			55
			20
			10
			20
			15
Total capacity replacement capital 165 168			120
Growth capital McArthur River/Key Lake 15 13 Cigar Lake 90 81 Inkai 15 11 Fuel services 5 1 Other - 1
			40
			30
			10
			5
			-
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 tierone 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.

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:

Sales Annual inflation

sales volumes on average of 27 million pounds per year,  is 2% in the US with commitment levels in 2016 through 2018 higher than in Prices 2019 and 2020
- the average long-term price indicator is the same as the
excludes sales between our uranium, fuel services and NUKEM segments average spot price for the entire year (a simplified approach for this purpose only). Since 1996, the long-term price

Deliveries indicator has averaged 19% higher than the spot price. This

deliveries include best estimates of requirements contracts differential has varied significantly. Assuming the long-term and contracts with volume flex provisions price is at a premium to spot, the prices in the table and graph will be higher.

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

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

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.

		INTEREST	TRANSFER
		AND INSTALMENT	PRICING		CASH	SECURED BY
YEAR PAID ($ MILLIONS)	CASH TAXES	PENALTIES	PENALTIES	TOTAL	REMITTANCE	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
	264 95 - 120 20 - 45 425 - 450
Secured by letters of credit
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
	 Transfer pricing methodology used for	US mines to CEL is inadequate
	certain intercompany uranium sale and	 Compensation earned by Cameco Inc.,
	purchase agreements	one of our US subsidiaries, is inadequate
	 Allocates Cameco Europe Ltd. (CEL)	 Allocates a portion of CEL’s income for the
	income (as adjusted) for 2003 through	years 2009 through 2012 to the US (a
	2010 to Canada (same income we paid tax	portion of the same income we paid tax on
	on in foreign jurisdictions and includes	in foreign jurisdictions and which the CRA
	income that IRS is proposing to tax)	is proposing to tax)
Years under consideration	 CRA reassessed 2003 to 2010	 IRS has proposed adjustments for 2009
	 Auditing 2011 to 2012	through 2012
Timing of resolution	 Expect our appeal of the 2003, 2005 and	 Contesting proposed adjustments in an
	2006 reassessments to commence during	administrative appeal
	the week of September 26, 2016, with final	 We cannot yet provide an estimate as to
	arguments expected in April 2017	the timeline for resolution
	 Expect Tax Court decision six to 18
	months after completion of trial
Required payments	 Expect to provide security in form of letters	 No security or cash payments required
	of credit and/or make cash payments for	while under administrative appeal
	50% of cash taxes, interest and penalties
	as reassessed
	 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 forwardlooking 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.

Assumptions Material risks that could cause actual results to differ materially

CRA will reassess us for the years 2011 through 2015 using  CRA reassesses us for years 2011 through 2015 using a a similar methodology as for the years 2003 through 2010, different methodology than for years 2003 through 2010, or and the reassessments will be issued on the basis we expect we are unable to utilize elective deductions or letters of credit
we will be able to apply elective deductions and utilize letters to the extent anticipated, resulting in the required cash payments or security provided to CRA pending the outcome of credit to the extent anticipated
CRA will seek to impose transfer pricing penalties (in a of the dispute being higher than expected
- the time lag for the reassessments for each year is different

manner consistent with penalties charged in the years 2007 through 2009) in addition to interest charges and instalment than we currently expect  penalties we are unsuccessful and the outcomes of our dispute with

we will be substantially successful in our dispute with CRA CRA and/or IRS result in significantly higher cash taxes, interest charges and penalties than the amount of our and the cumulative tax provision of $50 million to date will be adequate to satisfy any tax liability resulting from the cumulative tax provision, which could have a material outcome of the dispute to date adverse effect on our liquidity, financial position, results of
IRS may propose adjustments for later years subsequent to operations and cash flows 2012  cash tax payable increases due to unanticipated adjustments
we will be substantially successful in our dispute with IRS by CRA or IRS not related to transfer pricing
- IRS proposes adjustments for years 2013 through 2015 using a different methodology than for 2009 through 2012
- we are unable to effectively eliminate all double taxation

2015 financial results by segment

Uranium results

	THREE MONTHS ENDED			YEAR ENDED
	DECEMBER 31			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 ($US/lb) Average long-term price ($US/lb) Average realized price ($US/lb) ($Cdn/lb)	35.45	37.13 (5)% 48.00 (8)% 50.57 (8)% 56.78 8%		36.55	33.21 10% 46.46 - 47.53 (5)% 52.37 10%
	44.00			46.29
	46.36			45.19
	61.24			57.58
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.

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 fixedprice contracts, and the mix of market and fixed contracts. However, the effect of foreign exchange resulted in an 8% higher

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