Cameco reports fourth quarter and 2014 financial results

SASKATOON, SASKATCHEWAN--(Marketwired - Feb. 6, 2015) -

ALL AMOUNTS ARE STATED IN CDN $ (UNLESS NOTED)

• 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

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

(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.

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) (see non-IFRS measure section) 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
• 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) (see non-IFRS measure section) 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.

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 for details.

2015 FINANCIAL OUTLOOK

	CONSOLIDATED	URANIUM1	FUEL SERVICES	NUKEM1
Production	-	25.3 to 26.3 million lbs	9 to 10 million kgU	-
Sales volume1	-	31 to 33 million lbs	Decrease 5% to 10%	7 to 8 million lbs U3O8
Revenue compared to 20142	Decrease 0% to 5%	Decrease 5% to 10%3	Decrease 0% to 5%	Increase 5% to 10%
Average unit cost of sales(including D&A)	-	Increase 5% to 10%4	Increase 5% to 10%	Increase 0% to 5%
Direct administration costs compared to 20145	Increase 0% to 5%	-	-	Decrease 0% to 5%
Exploration costs compared to 2014	-	Decrease 5% to 10%	-	-
Tax rate	Recovery of 60% to 65%	-	-	Expense of 30% to 35%
Capital expenditures	$370 million	-	-	-

(1)	Our 2015 outlook for sales volume in our uranium and NUKEM segments does not include sales between our uranium, fuel services and NUKEM segments.
(2)	For comparison of our 2015 outlook and 2014 results for revenue in our uranium and NUKEM segments, we do not include sales between our uranium, fuel services and NUKEM segments.
(3)	Based on a uranium spot price of $37.50 (US) per pound (the Ux spot price as of February 2, 2015), a long-term price indicator of $49.00 (US) per pound (the Ux long-term indicator on January 26, 2015) and an exchange rate of $1.00 (US) for $1.10 (Cdn).
(4)	This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we make discretionary purchases in 2015, then we expect the overall unit cost of sales may be affected.
(5)	Direct administration costs do not include stock-based compensation expenses.

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.

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 U3O8)	$20	$40	$60	$80	$100	$120	$140
2015	41	46	55	63	72	80	87
2016	41	47	57	68	78	87	95
2017	41	46	57	67	78	87	94
2018	42	48	58	69	79	87	93
2019	43	49	59	69	78	85	91

The table 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:

Sales

• sales volumes on average of 27 million pounds per year, with commitment levels in 2015 through 2018 higher than in 2019
• excludes sales between our uranium, fuel services and NUKEM segments

Deliveries

• deliveries include best estimates of requirements contracts and contracts with volume flex provisions
• we defer a portion of deliveries under existing contracts for 2015

Annual inflation

• is 2% in the US

Prices

• the average long-term price indicator is the same as the average spot price for the entire year (a simplified approach for this purpose only). Since 1996, the long-term price indicator has averaged 18% higher than the spot price. This differential has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table will be 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
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. 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.

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.

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

(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.

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

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

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

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

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

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

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

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

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

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

Assumptions

• CRA will reassess us for the years 2010 through 2014 using a similar methodology as for the years 2003 through 2009, and the reassessments will be issued on the basis we expect
• we will be able to apply elective deductions and tax loss carryovers to the extent anticipated
• CRA will seek to impose transfer pricing penalties (in a manner consistent with penalties charged in the years 2007 through 2009) in addition to interest charges and instalment penalties
• we will be substantially successful in our dispute with CRA and the cumulative tax provision of $85 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date
• IRS will continue to propose adjustments for the years 2010 through 2012 and may propose adjustments for later years
• we will be substantially successful in our dispute with IRS

Material risks that could cause actual results to differ materially

• CRA reassesses us for years 2010 through 2014 using a different methodology than for years 2003 through 2009, or we are unable to utilize elective deductions and loss carryovers to the same extent as anticipated, resulting in the required cash payments to CRA pending the outcome of the dispute being higher than expected
• the time lag for the reassessments for each year is different than we currently expect
• we are unsuccessful and the outcomes of our dispute with CRA and/or IRS result in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision, which could have a material adverse effect on our liquidity, financial position, results of operations and cash flows
• cash tax payable increases due to unanticipated adjustments by CRA or IRS not related to transfer pricing
• IRS proposes adjustments for years 2010 through 2014 using a different methodology than for 2009
• we are unable to effectively eliminate all double taxation

2014 financial results by segment

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

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

Total cost of sales (including D&A) also increased by 9% ($1.18 billion compared to $1.08 billion in 2013) mainly due to slightly higher sales volumes and an increase in the average unit cost of sales resulting from an increase in non-cash costs. Total non-cash costs were $273 million compared to $213 million in 2013 as a result of an increase in the average non-cash unit cost of inventory.

The net effect was a $52 million increase in gross profit for the year.

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

		THREE MONTHS ENDED DECEMBER 31		CHANGE	YEAR ENDED DECEMBER 31		CHANGE
($Cdn/lb)		2014	2013		2014	2013
Produced
	Cash cost	14.19	15.61	(9)%	18.66	18.37	2%
	Non-cash cost	7.15	9.42	(24)%	9.30	9.46	(2)%
	Total production cost	21.34	25.03	(15)%	27.96	27.83	-
	Quantity produced (million lbs)	8.2	7.5	9%	23.3	23.6	(1)%
Purchased
	Cash cost	39.03	37.26	5%	38.17	27.95	37%
	Quantity purchased (million lbs)	3.7	4.4	(16)%	7.1	13.2	(46)%
Totals
	Produced and purchased costs	26.84	29.55	(9)%	30.34	27.87	9%
	Quantities produced and purchased (million lbs)	11.9	11.9	-	30.4	36.8	(17)%

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

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 quarters and years ended December 31, 2014 and December 31, 2013.

Cash and total cost per pound reconciliation
		THREE MONTHS ENDED DECEMBER 31		YEAR ENDED DECEMBER 31
($ MILLIONS)		2014	2013	2014	2013
Cost of product sold		269.0	359.8	902.8	869.1
Add / (subtract)
	Royalties	(34.5)	(52.5)	(91.2)	(90.8)
	Standby charges	-	(11.1)	(24.8)	(37.4)
	Other selling costs	(2.3)	(4.8)	(9.0)	(1.4)
	Change in inventories	28.5	(10.3)	(71.9)	63.1
Cash operating costs (a)		260.7	281.1	705.9	802.6
Add / (subtract)
	Depreciation and amortization	96.7	121.2	272.6	212.9
	Change in inventories	(38.0)	(50.7)	(56.2)	10.1
Total operating costs (b)		319.4	351.6	922.3	1,025.6
	Uranium produced and purchased (millions lbs) (c)	11.9	11.9	30.4	36.8
Cash costs per pound (a ÷ c)		21.91	23.62	23.22	21.81
Total costs per pound (b ÷ c)		26.84	29.55	30.34	27.87

Fuel services results
(includes results for UF6, UO2 and fuel fabrication)
	THREE MONTHS ENDED DECEMBER 31			YEAR ENDED DECEMBER 31
HIGHLIGHTS	2014	2013	CHANGE	2014	2013	CHANGE
Production volume (million kgU)	2.7	2.7	-	11.6	14.9	(22)%
Sales volume (million kgU)	7.41	6.5	14%	15.52	17.63	(12)%
Realized price ($Cdn/kgU)	16.92	17.24	(2)%	19.70	18.12	9%
Average unit cost of sales ($Cdn/kgU) (including D&A)	14.78	14.42	2%	17.24	15.16	14%
Revenue ($ millions)	1251	112	12%	3062	3193	(4)%
Gross profit ($ millions)	16	18	(11)%	38	52	(27)%
Gross profit (%)	13	16	(19)%	12	16	(25)%

(1)	Includes sales of 0.5 million kgU and revenue of $4 million between our uranium, fuel services and NUKEM segments.
(2)	Includes sales of 0.5 million kgU and revenue of $4 million between our uranium, fuel services and NUKEM segments.
(3)	Includes sales of 0.7 million kgU and revenue of $6 million between our uranium, fuel services and NUKEM segments.

FOURTH QUARTER

Total revenue increased by 12% due to a 14% increase in sales volumes, partially offset by a 2% decrease in average realized price.

The total cost of sales (including D&A) increased by 17% ($109 million compared to $93 million in the fourth quarter of 2013) mainly due to a 14% increase in sales volumes and a 2% increase in the average unit cost of sales.

The net effect was a $2 million decrease in gross profit.

FULL YEAR

Total revenue decreased by 4% due to a 12% decrease in sales volumes, partially offset by a 9% increase in the realized price.

The total cost of products and services sold (including D&A) remained relatively stable compared to 2013 at $268 million, as a 12% decrease in sales volume was offset by a 14% increase in the average unit cost of sales (including D&A).

The net effect was a $14 million decrease in gross profit.

NUKEM results
	THREE MONTHS ENDED DECEMBER 31			YEAR ENDED DECEMBER 31
HIGHLIGHTS	2014	2013	CHANGE	2014	2013	CHANGE
Uranium sales (million lbs)	3.41	3.3	3%	8.11	8.92	(9)%
Average realized price ($Cdn/lb)	52.12	41.84	25%	44.90	42.26	6%
Cost of product sold (including D&A)	156	169	(8)%	327	445	(27)%
Revenue	1591	188	(15)%	3491	4652	(25)%
Gross profit	3	19	(84)%	22	20	10%
Net earnings	(6)	13	(146)%	(3)	7	(143)%
Adjustments on derivatives3	-	(1)	100%	2	(3)	167%
NUKEM inventory write-down (reversal) (net of tax)	(2)	(1)	(100)%	(4)	10	(140)%
Adjusted net earnings (loss)3	(8)	11	(173)%	(5)	14	(136)%

(1)	Includes sales of 1.1 million pounds and revenue of $43 million between our uranium, fuel services and NUKEM segments.
(2)	Includes sales of 0.6 million pounds and revenue of $23 million between our uranium, fuel services and NUKEM segments.
(3)	Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (see non-IFRS measure section).

FOURTH QUARTER

During the three months ended December 31, 2014, NUKEM delivered 3.4 million pounds of uranium, an increase of 0.1 million pounds compared to 2013 due to timing of customer requirements. NUKEM revenues amounted to $159 million compared to $188 million in 2013 due to a decline in the uranium spot price relative to the previous year.

The unit cost of uranium sold was lower in 2014 as a result of the decline in the spot price.

The net effect was a $16 million decrease in gross profit. On a percentage basis, gross profits were 2% in the fourth quarter of 2014 compared to 10% in the same period in 2013.

Administration costs were higher in the fourth quarter due to the timing of expenditures. In addition, the sale of inventory on hand at the time of the acquisition of NUKEM resulted in an allocation of the historic purchase price to the sale of uranium in the quarter. This resulted in an adjusted net loss for the fourth quarter of 2014 of $8 million, compared to earnings of $11 million (see non-IFRS measure section) in 2013.

FULL YEAR

During 2014, NUKEM delivered 8.1 million pounds of uranium, a decrease of 0.8 million pounds compared to the previous year due to weak market conditions. Revenues from NUKEM amounted to $349 million, 25% lower than in 2013 as a result of lower sales volume and a decline in the realized price amid lower market prices.

Gross profit amounted to $22 million, an increase of $2 million compared to 2013. Although sales volumes decreased, NUKEM's gross margin increased by 10% compared to 2013 due to generally higher margin sales and a $14 million inventory write-down in 2013. On a percentage basis, gross profits were 6% in 2014 compared to 4% in the prior year.

After administration costs, interest and income taxes, adjusted net earnings amounted to a loss of $5 million compared to earnings of $14 million in 2013 (see non-IFRS measure section).

Our operations
CAMECO'S SHARE	THREE MONTHS ENDED DECEMBER 31		YEAR ENDED DECEMBER 31
(MILLION LBS)	2014	2013	2014	2013	2014 PLAN1	2015 PLAN
McArthur River/Key Lake	4.4	4.0	13.3	14.1	12.8	13.7
Rabbit Lake	2.1	2.1	4.2	4.1	4.1	3.9
Smith Ranch-Highland	0.6	0.5	2.1	1.7	2.0	1.4
Crow Butte	0.2	0.2	0.6	0.7	0.6	0.3
Inkai	0.7	0.7	2.9	3.0	3.0	3.0
Cigar Lake	0.2	-	0.2	-	0.1 - 0.3	3.0 - 4.0
Total	8.2	7.5	23.3	23.6	22.6 - 22.8	25.3 - 26.3

(1)	We updated our initial 2014 plan for McArthur River/Key Lake (to 12.8 from 13.1 million pounds) and Cigar Lake (to between 0.1 and 0.3 from between 1.0 and 1.5 million pounds) in our Q3 MD&A.

URANIUM PRODUCTION OUTLOOK

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

We plan to:

• ensure continued reliable, low-cost production from our flagship operation, McArthur River/Key Lake and seek to expand that production
• ensure continued reliable, low-cost production at Inkai
• successfully ramp up production at Cigar Lake
• manage the rest of our production facilities and other sources of supply in a manner that retains the flexibility to respond to market signals and take advantage of value adding opportunities within our own portfolio and the uranium market
• maintain our low-cost advantage by focusing on execution and operational excellence

MCARTHUR RIVER

Production from McArthur River/Key Lake was 19.1 million pounds; our share was 13.3 million pounds. This was 4% higher than our forecast for the year as a result of a record month of production at Key Lake in December. However, annual production was 6% lower than in 2013 due to a labour disruption that resulted in an unplanned shutdown of the operations for approximately 18 days during the third quarter of 2014.

In 2014, the CNSC approved the Environmental Assessment (EA) for the Key Lake extension, a project which involves increasing our tailings capacity and Key Lake's nominal annual production rate. We also received approval to increase the production limit at McArthur River. The licence conditions handbooks for these operations now allow:

• the Key Lake mill to produce up to 25 million pounds (100% basis) per year
• the McArthur River mine to produce up to 21 million pounds (100% basis) per year

With the approved EA, and once the Key Lake extension project is complete, mill production can be increased to closely follow production from the McArthur River mine.

McArthur River production expansion

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

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

• obtain all the necessary regulatory approvals
• expand the freeze plant and electrical distribution systems
• optimize the mine ventilation system
• improve our dewatering system and expand our water treatment capacity as required to mitigate capacity losses should mine development increase background water volumes
• expand the concrete distribution systems and batch plant capacity

New mining areas

New mining zones and increased mine production require increased ventilation and freeze capacity. In 2014, we continued to upgrade our electrical infrastructure on surface as part of our plan to address these future needs.

Underground, we began mining in zone 4 north during the fourth quarter of 2014.

Key Lake extension project and mill revitalization

The Key Lake mill began operating in 1983 and we continue to upgrade circuits with new technology to simplify operations and improve environmental performance. As part of the upgrades, we continued to construct a new calciner circuit, and expect to begin operating with the new calciner in 2015.

The revitalization plan is expected to allow the mill to increase its annual uranium production capability to closely follow annual production rates from the McArthur River mine.

Tailings capacity

This year, the CNSC approved the Key Lake extension EA, allowing us to deposit tailings to a higher level in the Deilmann tailing management facility. We now expect to have sufficient tailings capacity to mill all the known McArthur River mineral reserves and resources, should they be converted to reserves, with additional capacity to toll mill ore from other regional deposits.

Labour relations

The mine and mill experienced a labour disruption that resulted in an unplanned shutdown of the operations for approximately 18 days during the third quarter of 2014. On October 6, 2014, unionized employees at McArthur River and Key Lake accepted a new four-year contract that includes a 12% wage increase over the term of the agreement. The previous contract expired on December 31, 2013.

CIGAR LAKE

Total production from Cigar Lake was 340,000 pounds; our share was 170,000 pounds.

During the year, we:

• brought the Cigar Lake mine into production
• began processing the ore at AREVA's McClean Lake mill, which, in the third quarter, produced the first uranium concentrate from the Cigar Lake operation
• continued freezing the ground from surface to ensure frozen ore is available for future production years

Costs (all showing our share)

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

• invested about $1.2 billion for our share of the construction costs to develop Cigar Lake
• expensed about $91 million in remediation expenses
• expensed about $111 million in standby costs

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

• $83 million on the McClean Lake mill
• $16 million on standby costs, which were expensed, and ceased August 31, 2014

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

In addition, during the year, we spent:

• $57 million on operating costs
• $21 million to complete various capital projects at site
• $39 million on underground development

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

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

In 2015, we expect to:

• begin commercial production
• have three jet boring machines operating underground
• continue ramping up towards the planned full production rate of 18 million pounds (100% basis) by 2018

We expect Cigar Lake to produce between 6 million and 8 million packaged pounds in 2015; our share is 3 million to 4 million pounds. Based on our operating experience and productivity during rampup, we will adjust our annual production plans as necessary to allow us to reach our full production rate of 18 million pounds (100% basis) by 2018.

INKAI

Total production from Inkai was 5.1 million pounds; our share was 2.9 million pounds. Production was 3% lower than both our forecast for the year and our production in 2013. Inkai experienced delays in bringing on new wellfields as a result of abnormally heavy snowfall and a rapid spring melt in 2014.

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

• increase Inkai's annual production from blocks 1 and 2 to 10.4 million pounds (our share 5.2 million pounds) and sustain it at that level
• extend the term of Inkai's resource use contract through 2045

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

In 2014 at block 3, Inkai continued construction of the test leach facility and test wellfields, and advanced work on a preliminary appraisal of the mineral potential according to Kazakhstan standards. In 2015, Inkai expects to complete construction of the test leach facility and continue working on a final appraisal of the mineral potential according to Kazakhstan standards.

We expect total production from blocks 1 and 2 to be 5.2 million pounds in 2015; our share is 3.0 million pounds. We expect to maintain production at this level until the potential expansion under the 2012 MOA proceeds.

FUEL SERVICES

Fuel services produced 11.6 million kgU, lower than our plan at the beginning of the year and 22% lower than 2013. This was a result of a decision to decrease production in response to weak market conditions.

In 2014, amid the continued weak market for UF₆ conversion, we paid $18 million to SFL to permit early termination of our toll-conversion agreement. Production for Cameco at the Springfields facility in the United Kingdom ceased on August 31, 2014, and the agreement ended December 31, 2014.

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

We have decreased our production target for 2015 to between 9 million and 10 million kgU in response to weak market conditions.

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

Qualified persons

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

McArthur River/Key Lake

• David Bronkhorst, vice-president, mining and technology, Cameco
• Les Yesnik, general manager, Cigar Lake, Cameco

Cigar Lake

• Scott Bishop, manager, technical services, Cameco

Inkai

• Darryl Clark, general manager, JV Inkai

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 below, 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. We recommend you also review our annual information form and annual MD&A, which include 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

• the statement that we continue to see exceptional growth on the horizon
• the statement that we believe that when the market signals a need for more uranium, we will be well positioned to benefit from that growing demand
• the discussion under the heading 2014 market developments
• our expectations for uranium deliveries in the first quarter and for the balance of 2015
• our consolidated outlook for the year and the outlook for our uranium, fuel services and NUKEM segments for 2015
• our price sensitivity analysis for our uranium segment
• future tax payments and rates
• our expectations for 2015, 2016 and 2017 capital expenditures
• the discussion of our expectations relating to our transfer pricing disputes including our estimate of the amount and timing of expected cash taxes and transfer pricing penalties
• our future plans and expectations for each of our uranium operating properties and fuel services operating sites

Material risks

• actual sales volumes or market prices for any of our products or services are lower than we expect for any reason, including changes in market prices or loss of market share to a competitor
• we are adversely affected by changes in foreign currency exchange rates, interest rates or tax rates
• our production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms
• our estimates of production, purchases, costs, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate
• we are unable to enforce our legal rights under our existing agreements, permits or licences
• we are subject to litigation or arbitration that has an adverse outcome, including lack of success in our disputes with tax authorities
• we are unsuccessful in our dispute with CRA and this results in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision
• there are defects in, or challenges to, title to our properties
• our mineral reserve and resource estimates are not reliable, or we face unexpected or challenging geological, hydrological or mining conditions
• we are affected by environmental, safety and regulatory risks, including increased regulatory burdens or delays
• we cannot obtain or maintain necessary permits or approvals from government authorities
• we are unable to obtain an extension to the term of Inkai's block 3 exploration license, which expires in July 2015
• we are affected by political risks
• we are affected by terrorism, sabotage, blockades, civil unrest, social or political activism, accident or a deterioration in political support for, or demand for, nuclear energy
• we are impacted by changes in the regulation or public perception of the safety of nuclear power plants, which adversely affect the construction of new plants, the relicensing of existing plants and the demand for uranium
• there are changes to government regulations or policies that adversely affect us, including tax and trade laws and policies
• our uranium suppliers fail to fulfil delivery commitments
• our McArthur River development, mining or production plans are delayed or do not succeed for any reason
• our Cigar Lake development, mining or production plans are delayed or do not succeed, including as a result of any difficulties with the jet boring mining method or freezing the deposit to meet production targets, the third jet boring machine does not go into operation on schedule in 2015 or operate as expected, or any difficulties with the McClean Lake mill modifications or expansion or milling of Cigar Lake ore
• we are affected by natural phenomena, including inclement weather, fire, flood and earthquakes
• our operations are disrupted due to problems with our own or our customers' facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, equipment failure, lack of tailings capacity, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failures, transportation disruptions or accidents, or other development and operating risks

Material assumptions

• our expectations regarding sales and purchase volumes and prices for uranium and fuel services
• our expectations regarding the demand for uranium, the construction of new nuclear power plants and the relicensing of existing nuclear power plants not being more adversely affected than expected by changes in regulation or in the public perception of the safety of nuclear power plants
• our expected production level and production costs
• the assumptions regarding market conditions upon which we have based our capital expenditures expectations
• our expectations regarding spot prices and realized prices for uranium, and other factors discussed above, Price sensitivity analysis: uranium segment
• our expectations regarding tax rates and payments, foreign currency exchange rates and interest rates
• our expectations about the outcome of disputes with tax authorities
• our decommissioning and reclamation expenses
• our mineral reserve and resource estimates, and the assumptions upon which they are based, are reliable
• the geological, hydrological and other conditions at our mines
• our McArthur River development, mining and production plans succeed
• our Cigar Lake development, mining and production plans succeed, including the third jet boring machine goes into operation on schedule in 2015 and operates as expected, the jet boring mining method works as anticipated, and the deposit freezes as planned
• modification and expansion of the McClean Lake mill are completed as planned and the mill is able to process Cigar Lake ore as expected
• the term of Inkai's block 3 exploration licence does not expire in July 2015 and is instead extended
• our ability to continue to supply our products and services in the expected quantities and at the expected times
• our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals
• our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues, strikes or lockouts, underground floods, cave-ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents or other development or operating risks

Conference call

We invite you to join our fourth quarter conference call on Monday, February 9, 2015 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 15, 2015 by calling (800) 408-3053 (Canada and US) or (905) 694-9451 (Passcode 5846753#)

Additional information

Our 2014 annual management's discussion and analysis and annual audited financial statements will be available shortly on SEDAR at sedar.com, on EDGAR at sec.gov/edgar.shtml and on our website at cameco.com. Our 2014 annual information form is expected to be available later in February.

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 GmbH, unless otherwise indicated.