CCO.TO · 2015-02-06

Cameco reports fourth quarter and 2014 financial results delivered on our guidance with strong performance in a weak market environment another year of solid uranium segment results—record annual revenue, record average realized price,

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 2014 financial results

delivered on our guidance with strong performance in a weak market environment
another year of solid uranium segment results—record annual revenue, record average realized price,

and strong production

produced the first packaged uranium concentrate from Cigar Lake
write-down of $126 million in the fourth quarter related to our Rabbit Lake operation, due to the

deferral of various projects related to future planned production

received a notice of proposed adjustment (NOPA) from the US Internal Revenue Agency for our 2009

tax year

Saskatoon, Saskatchewan, Canada, February 6, 2015 . . . . . . . . . . . . . . . . . .

Cameco (TSX: CCO; NYSE: CCJ) today reported its consolidated financial and operating results for the fourth quarter ended December 31, 2014 in accordance with International Financial Reporting Standards (IFRS).

“The uncertainty in the uranium market has persisted for longer than expected, but 2014 was another year of strong financial and operational performance,” said president and CEO, Tim Gitzel. ”We have continued to meet and, in several areas, exceed our annual guidance.

“And when we look longer term, we continue to see exceptional growth on the horizon, as billions of dollars are being invested in reactor construction around the world—reactors that will need uranium. With our world-class, low-cost assets, we believe that when the market signals a need for more uranium, we will be well positioned to benefit from that growing demand.”

HIGHLIGHTS	THREE MONTHS ENDED			YEAR ENDED
	DECEMBER 31			DECEMBER 31
($ MILLIONS EXCEPT PER SHARE AMOUNTS)	2014	2013	CHANGE	2014	2013	CHANGE
Revenue		977 (9)%			2,439 (2)%
	889			2,398
Gross profit		185 36%			607 5%
	251			638
Net earnings attributable to equity holders		64 14%			318 (42)%
	73			185
$ per common share (basic and diluted)		0.16 13%			0.81 (42)%
	0.18			0.47
Adjusted net earnings (non-IFRS, see page 8)		150 37%			445 (7)%
	205			412
$ per common share (adjusted and diluted)		0.38 37%			1.12 (7)%
	0.52			1.04
Cash provided by continuing operations (after working capital changes)1		163 45%			524 (8)%
	236			480
Average Uranium $US/lb realized prices $Cdn/lb Fuel services $Cdn/kgU NUKEM $Cdn/lb	50.57	47.76 6% 49.80 14%		47.53	48.35 (2)% 49.81 5%
	56.78			52.37
		17.24 (2)%			18.12 9%
	16.92			19.70
		41.84 25%			42.26 6%
	52.12			44.90

1 For comparison purposes, our results have been revised to exclude BPLP. The impact of BPLP is shown separately in our annual MD&A as a discontinued operation.

The 2014 annual financial statements have been audited; however, the 2013 and 2014 fourth quarter financial information presented is unaudited. You can find a copy of our 2014 audited financial statements on our website at cameco.com. Our 2014 annual management’s discussion and analysis (MD&A) will be posted on our website before markets open on Monday, February 9, 2015.

‐ 1 ‐

FULL YEAR

Our net earnings attributed to equity holders (net earnings) were $185 million ($0.47 per share diluted)

compared to $318 million ($0.81 per share diluted) in 2013, mainly due to:

write-downs totalling $327 million of our investments in Eagle Point mine assets at Rabbit Lake – $126 million, GLE – $184 million, and Goviex – $17 million
no earnings from Bruce Power Limited Partnership (BPLP), which we divested in the first quarter of 2014
the write-off of $41 million of assets under construction as a result of changes made to the scope of a number of projects
an early termination fee of $18 million incurred as a result of the cancellation of our toll conversion agreement with Springfields Fuels Limited (SFL), which was to expire in 2016
settlement costs of $12 million with respect to the early redemption of our Series C debentures
lower earnings in our fuel services segment as a result of a decrease in sales volumes and higher unit cost of sales
higher losses on foreign exchange derivatives due to the weakening of the Canadian dollar

partially offset by:

a $127 million gain on the sale of our interest in BPLP
higher earnings in our uranium segment due to higher average realized prices
a favourable settlement of $66 million in a dispute regarding a long-term supply contract with a utility customer
lower exploration costs due to a more focused effort on our core projects in Saskatchewan, with decreases in activity elsewhere, particularly in Australia and at Inkai
higher tax recoveries resulting from pre-tax losses in Canada

On an adjusted basis, our earnings were $412 million ($1.04 per share diluted) (non-IFRS measure, see page

8) compared to $445 million ($1.12 per share diluted) in 2013, mainly due to:

no earnings from BPLP due to divestiture of our interest in the first quarter of 2014
an early termination fee of $18 million incurred as a result of the cancellation of our toll conversion agreement with SFL, which was to expire in 2016
settlement costs of $12 million with respect to the early redemption of our Series C debentures
lower earnings from our fuel services business as a result of lower sales volumes and higher unit cost of sales
higher losses on foreign exchange derivatives due to the weakening of the Canadian dollar

partially offset by:

higher earnings in our uranium segment due to higher average realized prices
a favourable settlement of $66 million with respect to a dispute regarding a long-term supply contract with a utility customer
lower exploration costs due to a more focused effort on our core projects in Saskatchewan, with decreases in activity elsewhere, particularly at our Kintyre project in Australia and at Inkai

FOURTH QUARTER

In the fourth quarter of 2014, our net earnings were $73 million ($0.18 per share diluted), an increase of $9 million compared to $64 million ($0.16 per share diluted) in 2013, mainly due to:

higher uranium gross profits resulting from higher average realized prices and lower average unit cost of sales
a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer
lower exploration expenditures
higher income tax recovery

partially offset by:

the impact of a $126 million write-down of our investments in the Eagle Point mine assets at Rabbit Lake
the write-off of $41 million of assets under construction as a result of changes made to the scope of a number of projects

‐ 2 ‐

no earnings from BPLP due to divestiture of our interest in the first quarter of 2014
higher losses on foreign exchange derivatives resulting from the weakening of the Canadian dollar

On an adjusted basis, our earnings this quarter were $205 million ($0.52 per share diluted) compared to $150 million ($0.38 per share diluted) (non-IFRS measure, see page 8) in the fourth quarter of 2013, mainly due to:

higher uranium gross profits due to higher average realized price and lower average unit cost of sales
a favourable settlement of $37 million with respect to a dispute regarding a long-term supply contract with a utility customer
lower exploration expenditures

partially offset by:

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

IMPAIRMENT CHARGE ON PRODUCING ASSETS

During the fourth quarter of 2014, we recognized a $126 million impairment charge related to our Rabbit Lake operation. The impairment was due to the deferral of various projects that were related to planned production over the remaining life of the Eagle Point mine. The amount of the charge was determined as the excess of the carrying value over the recoverable amount. The recoverable amount of the mine was determined to be $29 million. See note 10 of the financial statements.

2014 market developments

Today, the uranium market is in a state of oversupply, and there are a number of factors contributing: primary supply continues to perform relatively well; enrichers are underfeeding their plants in reaction to excess enrichment capacity, which creates another source of uranium that’s being put onto the spot market; and Japanese reactors remain idled, meaning their inventories continue to grow. We do not believe those inventories are coming to market, but it removes Japanese utilities from the market as buyers for the time being.

SUPPLY AND DEMAND

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

CONTRACTING

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

JAPAN

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

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OTHER REGIONS

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

In 2014, growth was tangible as five reactors came online: three in China, one in Argentina, and one in Russia. It was also exciting to see two emerging nuclear countries start construction on reactors: one in the United Arab Emirates and one in Belarus.

Outlook for 2015

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

Our outlook for 2015 reflects the expenditures necessary to help us achieve our strategy. We do not provide an outlook for the items in the table that are marked with a dash.

See 2014 Financial results by segment on page 12 for details.

2015 FINANCIAL OUTLOOK

	CONSOLIDATED	URANIUM1	FUEL SERVICES	NUKEM1
	25.3 to 26.3 - million lbs		9 to 10 million kgU
Production				-
	31 to 33 - million lbs		Decrease 5% to 10%	7 to 8
Sales volume1
				million lbs UO 3 8
	Decrease 0% to 5%	Decrease	Decrease 0% to 5%	Increase
Revenue compared to 20142
		5% to 10%3		5% to 10%
Average unit cost of sales	-	Increase	Increase 5% to 10%	Increase
(including D&A)		5% to 10%4		0% to 5%
Direct administration costs	Increase 0% to 5%		-	Decrease
		-
compared to 20145				0% to 5%
Exploration costs compared to	-	Decrease	-
				-
2014		5% to 10%
	Recovery of 60% to 65%		-	Expense of
Tax rate		-
				30% to 35%
Capital expenditures	$370 million	-	-	-

1 Our 2015 outlook for sales volume in our uranium and NUKEM segments does not include sales between our uranium, fuel services and NUKEM segments.

2 For comparison of our 2015 outlook and 2014 results for revenue in our uranium and NUKEM segments, we do not include sales between our uranium, fuel services and NUKEM segments.

3 Based on a uranium spot price of $37.50 (US) per pound (the Ux spot price as of February 2, 2015), a long-term price indicator of $49.00 (US) per pound (the Ux long-term indicator on January 26, 2015) and an exchange rate of $1.00 (US) for $1.10 (Cdn). 4 This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we make discretionary purchases in 2015, then we expect the overall unit cost of sales may be affected.

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

CONSOLIDATED OUTLOOK

We expect consolidated revenue to decrease up to 5% in 2015 due to an expected decrease in uranium and fuel services sales volumes.

We expect administration costs (not including stock-based compensation) to be up to 5% higher compared to 2014.

We expect exploration expenses to be about 5% to 10% lower than they were in 2014 due to decreased spending at Inkai.

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

‐ 4 ‐

On an adjusted net earnings basis, we expect a tax recovery of 60% to 65% in 2015 from our uranium, fuel services and NUKEM segments, as taxable income in Canada is expected to decline. In 2016, the older contractual arrangements under our portfolio of intercompany sale and purchase arrangements largely expire, and we expect our portfolio to be increasingly reflective of the market at the time transactions occur under the contracts. As this transition occurs, we expect our consolidated tax rate to increase from a recovery to an expense, however the rate of change will depend on market conditions at the time new contracts are put in place and when transactions occur under the contracts.

URANIUM OUTLOOK

We expect to produce 25.3 million to 26.3 million pounds in 2015 and have commitments under long-term contracts to purchase approximately 2 million pounds.

Based on the contracts we have in place and not including sales between our segments, we expect to deliver between 31 million and 33 million pounds of U3O8 in 2015. We expect the unit cost of sales to be 5% to 10% higher than in 2014, primarily due to higher costs for produced material. As Cigar Lake ramps up to full production, the cash cost of material produced from the mine will initially be higher. If we make additional discretionary purchases in 2015 at a cost different than our other sources of supply, then we expect the overall unit cost of sales to be affected.

We expect revenue to be 5% to 10% lower than it was in 2014 as a result of an expected decrease in deliveries, not including sales between our segments, and a lower average realized price.

In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns and, therefore, our sales volumes and revenue, can vary significantly. We expect the quarterly distribution of uranium deliveries to be relatively balanced in 2015. However, not all delivery notices have been received to date, which could alter the delivery pattern. Typically, we receive notices six months in advance of the requested delivery date.

PRICE SENSITIVITY ANALYSIS: URANIUM SEGMENT

The table below is not a forecast of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table. It is designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2014 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on December 31, 2014, and none of the assumptions we list below change.

We intend to update this table 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 UO) 3 8	$20	$40	$60	$80	$100	$120	$140
2015	41	46	55	63	72	80	87
2016	41	47	57	68	78	87	95
2017	41	46	57	67	78	87	94
2018	42	48	58	69	79	87	93
2019	43	49	59	69	78	85	91

The table illustrates the mix of long-term contracts in our December 31, 2014 portfolio, and is consistent with our marketing strategy. It has been updated to reflect deliveries made and contracts entered into up to December 31, 2014.

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

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

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Sales Annual inflation

sales volumes on average of 27 million pounds per  is 2% in the US year, with commitment levels in 2015 through 2018 Prices higher than in 2019  the average long-term price indicator is the same as

 excludes sales between our uranium, fuel services the average spot price for the entire year (a and NUKEM segments simplified approach for this purpose only). Since Deliveries 1996, the long-term price indicator has averaged

deliveries include best estimates of requirements 18% higher than the spot price. This differential has contracts and contracts with volume flex provisions varied significantly. Assuming the long-term price is
we defer a portion of deliveries under existing at a premium to spot, the prices in the table will be contracts for 2015 higher.

FUEL SERVICES OUTLOOK

In 2015, we plan to produce 9 million to 10 million kgU, and we expect sales volumes not including intersegment sales to be 5% to 10% lower than in 2014. Overall revenue is expected to decrease by up to 5% as lower sales volumes will be partially offset by an increase in the average realized price. We expect the average unit cost of sales (including D&A) to increase by 5% to 10%; therefore, overall gross profit will decrease as a result.

NUKEM OUTLOOK

For 2015, NUKEM expects to deliver between 7 million and 8 million pounds of uranium, resulting in an increase in revenues not including intersegment sales, of 5% to 10% compared to 2014. NUKEM expects to incur administration costs up to 5% lower than in 2014. The effective income tax rate is expected to remain in the range of 30% to 35%.

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)	2014 PLAN	2014 ACTUAL	2015 PLAN
Sustaining capital
McArthur River/Key Lake	25	22	25
Cigar Lake	25	14	15
Rabbit Lake	45	33	35
US ISR	5	3	5
Inkai	10	9	5
Fuel services	10	8	15
Other	15	6	5
Total sustaining capital	135	95	105
Capacity replacement capital
McArthur River/Key Lake	55	57	85
Cigar Lake	35	38	35
Rabbit Lake	-	-	-
US ISR	20	23	20
Inkai	15	10	15
Total capacity replacement capital	125	128	155

‐ 6 ‐

Growth capital
McArthur River/Key Lake	60	51	25
Cigar Lake	155	186	70
US ISR	5	2	-
Inkai	5	10	5
Fuel services	5	6	5
Other	-	2	5
Total growth capital	230	257	110
Total uranium & fuel services 4901 480			370

1 Capital spending outlook was updated to $490 million in our third quarter MD&A.

OUTLOOK FOR INVESTING ACTIVITIES

(CAMECO’S SHARE IN $ MILLIONS)	2016 PLAN	2017 PLAN
Total uranium & fuel services	300-350	350-400
Sustaining capital	125-140	155-170
Capacity replacement capital	100-115	125-140
Growth capital	75-95	70-90

We expect total capital expenditures for uranium and fuel services to decrease by about 23% in 2015.

Major sustaining, capacity replacement and growth expenditures in 2015 include:

McArthur River/Key Lake – At McArthur River, the largest projects are the upgrade of the electrical infrastructure, the expansion of freeze capacity and mine development. Other projects include site facility and equipment purchases. At Key Lake, work will be completed on the calciner.
US in situ recovery (ISR) – wellfield construction represents the largest portion of our expenditures in the US.
Rabbit Lake – At Eagle Point, the largest component is mine development, along with mine equipment upgrades and purchases. Work on various mill facility and equipment replacements will also continue.
Cigar Lake – Underground mine development makes up the largest portion of capital at the Cigar Lake site. We are also paying our share of the costs to modify and expand the McClean Lake mill.

We previously expected to spend between $400 million and $450 million in 2015, and between $500 million and $550 million in 2016. We now expect to spend $370 million in 2015 and between $300 million and $350 million in 2016. The change is due to the removal of our fixed production target and the decrease in spending on the related projects. As the market begins to signal new production is needed, we plan to increase our capital expenditures to allow us to be among the first to respond to the growth we see coming.

This information regarding currently expected capital expenditures for future periods is forward-looking information, and is based upon the assumptions and subject to the material risks discussed beginning on page

19. Our actual capital expenditures for future periods may be significantly different.

ACQUISITIONS AND DIVESTITURES

On January 30, 2014, we signed an agreement with BPC Generation Infrastructure Trust to sell our 31.6% limited partnership interest in BPLP and related entities for $450 million. The effective date for the sale is January 1, 2014. We have realized an after tax gain of $127 million on this divestiture.

REVENUE AND EARNINGS SENSITIVITY ANALYSIS

At December 31, 2014, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2015 net earnings by about $7 million (Cdn), with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact. This sensitivity is based on an exchange rate of $1.00 (US) for $1.00 (Cdn).

For 2015, a change of $5 (US) per pound in each of the Ux spot price ($37.50 (US) per pound on February 2, 2015) and the Ux long-term price indicator ($49.00 (US) per pound on January 26, 2015) would change revenue by $93 million and net earnings by $55 million.

‐ 7 ‐

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 following table reconciles adjusted net earnings with our net earnings for the quarters and years ended December 31, 2014 and December 31, 2013.

	THREE MONTHS ENDED		YEAR ENDED
	DECEMBER 31		DECEMBER 31
($ MILLIONS)	2014	2013	2014	2013
Net earnings attributable to equity holders		64		318
	73		185
Adjustments Adjustments on derivatives1 Impairment charges Write-off of assets NUKEM inventory write-down (recovery) Loss on exploration properties Gain on interest in BPLP (after tax) Income taxes on adjustments		36 70 - (3) - - (17)		56 70 - 14 15 - (28)
	10		47
	131		327
	41		41
	(4)		(5)
	-		-
	-		(127)
	(46)		(56)
Adjusted net earnings		150		445
	205		412

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

TRANSFER PRICING DISPUTES

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

Transfer pricing is a complex area of tax law, and it is difficult to predict the outcome of cases like ours.

However, tax authorities generally test two things:

the governance (structure) of the corporate entities involved in the transactions
the price at which goods and services are sold by one member of a corporate group to another

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

‐ 8 ‐

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

CRA Dispute

Since 2008, CRA has disputed our corporate structure and the related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2009 tax returns. We have recorded a cumulative tax provision of $85 million, where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 through 2014. We continue to believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.

We are confident that we will be successful in our case; however, for the years 2003 through 2009, CRA issued notices of reassessment for approximately $2.8 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $820 million. CRA has also issued notices of reassessment for transfer pricing penalties for the years 2007 through 2009 in the amount of $229 million, including notices of reassessment recently received for transfer pricing penalties of an aggregate of $156 million for the 2008 and 2009 tax years. We have not yet made any remittance related to the 2008 and 2009 transfer pricing penalties. The Canadian income tax rules include provisions that require larger companies like us to remit 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions and tax loss carryovers, we have paid a net amount of $212 million cash to the Government of Canada, which includes the amounts shown in the table below. As an alternative to paying cash, we are exploring the possibility of providing security in the form of letters of credit to satisfy our requirements under these provisions.

YEAR PAID ($		INTEREST AND	TRANSFER PRICING
MILLIONS)	CASH TAXES	INSTALMENT PENALTIES	PENALTIES	TOTAL
Prior to 2013	-	13	-	13
2013	1	9	36	46
2014	106	47	-	153
Total	107	69	36	212

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

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

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

1 These amounts do not include interest and instalment penalties, which totalled approximately $69 million to December 31, 2014.

In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to the Government of Canada, including the $212 million already paid to date.

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

IRS dispute

As noted above, we received a NOPA from the IRS pertaining to the 2009 tax year for certain of our US subsidiaries.

In general, a NOPA is used by the IRS to communicate a proposed adjustment to income and provides the basis upon which the IRS will issue a Revenue Agent’s Report (RAR), which lists the adjustments proposed by the IRS and calculates the tax and any penalties owing based on the proposed adjustments. We currently anticipate receiving a RAR in the first quarter of 2015.

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

the prices received by our US mining subsidiaries for the sale of uranium to CEL are too low
the compensation being earned by Cameco Inc., one of our US subsidiaries, is inadequate

The proposed adjustment results in an increase in taxable income in the US of approximately $108 million (US) and a corresponding increased income tax expense of approximately $32 million (US) for the 2009 taxation year, with interest being charged thereon. In addition, the IRS may apply penalties in respect of the adjustment.

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

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

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

Overview of disputes

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

	CRA	IRS
Basis for dispute	 Corporate structure/governance  Transfer pricing methodology used for certain intercompany uranium sale and purchase agreements  Allocates Cameco Europe Ltd. (CEL) income (as adjusted) for 2003 through 2009 to Canada (same income we paid tax on in foreign jurisdictions and includes income that IRS is proposing to tax)	 Income earned on sales of uranium
		by the US mines to CEL is
		inadequate
		 Compensation earned by Cameco
		Inc., one of our US subsidiaries, is
		inadequate
		 Allocates a portion of CEL’s 2009
		income to the US (a portion of the
		same income we paid tax on in
		foreign jurisdictions and which the
		CRA is proposing to tax)

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	CRA	IRS
Years under considerations	 CRA reassessed 2003 to 2009	 IRS issued Notice of Proposed
	 Auditing 2010 to 2012	Adjustment (NOPA) for 2009
		 Auditing 2010 to 2012
Timing of resolution	 Expect our appeal of the 2003	 Expect Revenue Agent’s Report
	reassessment to be heard in the Tax	(follows NOPA) in Q1 2015
	Court in 2016	 Plan to contest proposed
	 Expect Tax Court decision six to 18	adjustments in an administrative
	months after completion of trial	appeal
		 This dispute is at an early stage, and
		we cannot yet provide an estimate as
		to the timeline for resolution
Required payments	 Expect to remit 50% of cash taxes,	 No payments required while under
	interest and penalties as reassessed	administrative appeal
	 Paid $212 million in cash to date
	 Exploring possibility of providing
	security in the form of letters of credit
	to satisfy required remittances

_________

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

This discussion of our expectations relating to our tax disputes with CRA and IRS and future tax reassessments by CRA and IRS is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 19 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

CRA will reassess us for the years 2010 through 2014 materially using a similar methodology as for the years 2003  CRA reassesses us for years 2010 through 2014 using through 2009, and the reassessments will be issued on a different methodology than for years 2003 through the basis we expect 2009, or we are unable to utilize elective deductions and
we will be able to apply elective deductions and tax loss loss carryovers to the same extent as anticipated, carryovers to the extent anticipated resulting in the required cash payments to CRA pending the outcome of the dispute being higher than expected
CRA will seek to impose transfer pricing penalties (in a manner consistent with penalties charged in the years  the time lag for the reassessments for each year is 2007 through 2009) in addition to interest charges and different than we currently expect instalment penalties  we are unsuccessful and the outcomes of our dispute
we will be substantially successful in our dispute with with CRA and/or IRS result in significantly higher cash CRA and the cumulative tax provision of $85 million to taxes, interest charges and penalties than the amount of our cumulative tax provision, which could have a date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date material adverse effect on our liquidity, financial position, results of operations and cash flows
IRS will continue to propose adjustments for the years 2010 through 2012 and may propose adjustments for  cash tax payable increases due to unanticipated later years adjustments by CRA or IRS not related to transfer
we will be substantially successful in our dispute with pricing
- IRS proposes adjustments for years 2010 through 2014

IRS using a different methodology than for 2009

we are unable to effectively eliminate all double taxation

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2014 financial results by segment Uranium results

	THREE MONTHS ENDED			YEAR ENDED
	DECEMBER 31			DECEMBER 31
HIGHLIGHTS	2014	2013	CHANGE	2014	2013	CHANGE
Production volume (million lbs)		7.5 9%			23.6 (1)%
	8.2			23.3
Sales volume (million lbs)		12.7 (16)%			32.8 3%
	10.71			33.92
Average spot price ($US/lb) Average long-term price ($US/lb) Average realized price ($US/lb) ($Cdn/lb)	37.13	35.03 6% 50.00 (4)% 47.76 6% 49.80 14%		33.21	38.17 (13)% 54.13 (14)% 48.35 (2)% 49.81 5%
	48.00			46.46
	50.57			47.53
	56.78			52.37
Average unit cost of sales ($Cdn/lb) (including D&A)		37.94 (10)%			33.01 5%
	34.27			34.64
Revenue ($ millions)		631 (4)%			1,633 9%
	6061			1,7772
Gross profit ($ millions)		150 60%			550 9%
	240			602
Gross profit (%)		24 67%			34 -
	40			34

1 Includes sales of 0.4 million pounds and revenue of $15 million between our uranium, fuel services and NUKEM segments.

2 Includes sales of 1.4 million pounds and revenue of $48 million between our uranium, fuel services and NUKEM segments.

FOURTH QUARTER

Production volumes this quarter were 9% higher compared to the fourth quarter of 2013, mainly as a result of higher production at McArthur River/Key Lake, in addition to the first production from Cigar Lake/McClean Lake. See Our operations starting on page 16 for more information.

Uranium revenues were down 4% due to a 16% decrease in sales volumes, which represents normal quarterly variance in our delivery schedule, offset by a 14% increase in average realized price.

The average realized price increased by 14% compared to 2013 due to higher US dollar prices under fixed price contracts, and the effect of foreign exchange. In the fourth quarter of 2014, our realized foreign exchange rate was $1.12 compared to $1.04 in the prior year.

Total cost of sales (including D&A) decreased by 24% ($366 million compared to $481 million in 2013). This was the result of a 10% decrease in the average unit cost of sales and a 16% decrease in sales volumes.

The unit cost of sales decreased due to a decrease in the cash costs of produced material in the fourth quarter compared to the same period in 2013, as a result of increased production and timing of royalties. In addition, standby charges for the McClean Lake mill ceased in the fourth quarter, as production from Cigar Lake commenced.

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

FULL YEAR

Production volumes in 2014 did not vary significantly from 2013. Lower production at McArthur River/Key Lake was offset by higher production at other sites. See Our operations on page 16 for more information.

Uranium revenues this year were up 9% compared to 2013 due to an increase in sales volumes of 3% and an increase of 5% in the Canadian dollar average realized price. Although the spot and term prices were lower than 2013, our average realized prices remained fairly constant compared to 2013, as lower market-related prices were largely offset by higher US dollar prices under fixed price contracts. The effect of foreign exchange resulted in a higher Canadian dollar average realized price than in the prior year. The realized foreign exchange rate was $1.10 compared to $1.03 in 2013. The spot price for uranium averaged $33.21 (US) per pound in 2014, a decline of 13% compared to the 2013 average price of $38.17 (US) per pound.

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