CCO.TO · 2012-02-09

Cameco reports fourth quarter and 2011 financial results delivered a strong fourth quarter—record reve nue and gross profit from our nuclear business record annual revenue and gross profit from our nuclear business, and record revenue and realized

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 2011 financial results

delivered a strong fourth quarter—record revenue and gross profit from our nuclear business
record annual revenue and gross profit from our nuclear business, and record revenue and realized

prices in our uranium segment

uranium production 3% higher than plan—on track with our Double U strategy
matched our 2010 production record at McArthur River/Key Lake
continued progress at Cigar Lake—broke through on the 480 metre level, putting it on the path to become

another source of high-grade, low-cost production

Saskatoon, Saskatchewan, Canada, February 9, 2012 . . . . . . . . . . . . . . . . . . . Cameco (TSX: CCO; NYSE: CCJ) today reported its consolidated financial and operating results for the fourth quarter ended December 31, 2011 and for the year.

“2011 was a challenging year for the nuclear industry,” said CEO Tim Gitzel. “However, it was business as usual for us, and in some ways, even better than usual. We achieved a number of financial records including record revenue and gross profit from our nuclear business and record realized prices for uranium. At our operations we delivered on a number of key milestones in a safe and responsible manner.

“Looking forward, we remain confident in the long-term fundamentals of the nuclear industry. With our extraordinary assets, contract portfolio, employee expertise, industry knowledge and financial strength, we are well positioned to meet the growing demand for uranium and add value for our shareholders.”

Highlights ($ millions except per share amounts)		Three months ended				Year ended December 31
		December 31
		2011		2010	change		2011		2010	change
Revenue		977	673 45%				2,384	2,124 12%
Gross profit		353	252 40%				776	771 1%
Net earnings1		265	206 29%				450	516 (13)%
$ per common share (basic and diluted)		0.67	0.52 29%				1.14	1.31 (13)%
Adjusted net earnings (non-IFRS, see page 9)		249	190 31%				509	497 2%
$ per common share (adjusted and diluted)		0.63	0.48 31%				1.29	1.26 2%
Cash provided by operations (after working capital changes)	255	255	109 134%			732	732	521 40%

1 Net earnings attributable to our shareholders.

The 2011 annual financial statements have been audited; however, the 2010 and 2011 fourth quarter financial information presented is unaudited. You can find a copy of our 2011 audited financial statements on our website at cameco.com. Our 2011 annual management’s discussion and analysis (MD&A) will be posted on our website on Thursday, February 9, 2012.

Transition to IFRS

On January 1, 2011, we adopted International Financial Reporting Standards (IFRS) for Canadian publicly accountable enterprises. Our financial statements have been prepared using IFRS. Amounts relating to the year ended December 31, 2010 in this document and our related financial statements have been revised using IFRS for comparative purposes. Amounts for periods prior to January 1, 2010 are presented in accordance with Canadian GAAP in effect prior to January 1, 2011.

Full year

Net earnings attributable to our shareholders (net earnings) for the year were $450 million ($1.14 per share diluted) compared to $516 million ($1.31 per share diluted) in 2010. In addition to the items noted below, our net earnings were impacted by losses on foreign exchange derivatives compared to gains in 2010.

On an adjusted basis, our earnings for the year were $509 million ($1.29 per share adjusted and diluted) compared to $497 million ($1.26 per share adjusted and diluted) (non-IFRS, see page 9). The 2% increase resulted from:

higher earnings from our uranium business due to higher realized prices, and an increase in sales volumes

partially offset by:

an increase in the cost of sales
lower earnings from our electricity business due to higher costs, lower realized prices and lower sales volumes
lower earnings from our fuel services business resulting from higher costs, partially offset by higher sales volumes
higher income taxes due to an increase in the provision related to our transfer pricing dispute with the Canadian Revenue Agency (CRA)

See 2011 Financial results by segment on page 10 for more detailed discussion.

In the fourth quarter of 2011, our net earnings were $265 million ($0.67 per share diluted), an increase of $59 million compared to $206 million ($0.52 per share diluted) in 2010. Uranium revenues were up significantly due to an increase in sales volumes and an increase in the average realized selling price, partially offset by lower results in the electricity business due to lower sales volumes and a lower realized price.

On an adjusted basis, our earnings this quarter were $249 million ($0.63 per share diluted) compared to $190 million ($0.48 per share diluted) (non-IFRS, see page 9) in the fourth quarter of 2010. The 31% increase in adjusted net earnings in the quarter followed the same trend as our net earnings, due to our positive results in the uranium business partially offset by our results in the electricity business.

See 2011 Financial results by segment on page 10 for more detailed discussion.

The nuclear energy industry today

The nuclear energy industry addressed significant challenges in 2011 related to events at the Fukushima-Daiichi nuclear power plant in Japan. As a result, the outlook for the industry remains uncertain for the near to medium term. In the long term, however, we continue to see a very strong and promising growth profile for the nuclear industry.

On March 11, an earthquake and tsunami in Japan caused cooling systems at the Fukushima-Daiichi nuclear power station to fail, and radioactive materials were released. This reduced public confidence in nuclear power in some countries, most notably Germany, which represents 5% of world nuclear generating capacity. It decided to revert to its previous phase-out policy, shutting down eight of its reactors, and plans to shut down the remaining nine reactors by 2022.

It remains unclear what level of nuclear power Japan itself—which represents 12% of global nuclear generating capacity—will depend on in the future. As of February 8, 2012, Japan had three reactors operating. These three reactors are scheduled to enter regular maintenance shutdowns between late February and the end of April, at which time we expect all of Japan’s nuclear reactors will be offline. Many are unaffected by the events in March 2011 but are offline for both planned and unplanned maintenance outages, and diminished public support has prevented utilities from gaining the regulatory and political approvals necessary to restart them. The Japanese government has

ordered stress tests to be conducted on all reactors before allowing them to restart, and is implementing reforms to its existing nuclear regulatory framework and energy policy. Stress tests are progressing, but the government has not made any final decisions about restarting the reactors. Local government approval will also likely be required to allow reactors to restart.

The current operating status of reactors in Germany and Japan has caused concern that, in the near to medium term, additional volumes could be introduced to the market from deferrals and/or cancellations of deliveries under sales contracts. This has caused market participants to be discretionary in their purchases. We believe that utilities will continue to work with producers to manage these materials and minimize the impact on the market.

Industry taking action

At the same time, the industry has taken action. Countries with nuclear programs are reviewing regulatory standards, assessing the safety of existing facilities and the design of reactors under construction or in the planning stage. Third party organizations such as the International Atomic Energy Association, Nuclear Energy Institute, World Association of Nuclear Operators, Institute of Nuclear Power Operators, and the World Nuclear Association are lending their support and technical expertise to governments and operators, and providing an accurate source of information for the public.

Preliminary safety reviews are now complete and lessons are being applied that we expect will make the industry even safer. Most countries with nuclear generation capacity have reconfirmed their commitment to the technology and to the future of nuclear energy.

Long-term outlook is positive

Electricity is essential to maintaining and improving the standard of living for people around the world. Demand for safe, clean, reliable, affordable energy continues to grow and the need for nuclear as part of the world’s energy mix remains compelling. We expect demand for uranium to grow, and along with it the need for new supply to meet future customer requirements. You can read more about our outlook on future supply and demand in our annual MD&A.

Cameco well positioned

During this period of uncertainty, we are in the enviable position of being heavily committed under long-term sales contracts through 2016. As well, we have commitments to supply a total of about 290 million pounds of uranium under all of our long-term contracts, many of which extend beyond 2016. Therefore, we expect to have a solid revenue stream for years to come, even in the event of declining uranium market prices.

Outlook for 2012

Over the next several years, we expect to invest significantly in expanding production at existing mines and advancing projects as we pursue our growth strategy. The projects are at various stages of development, from exploration and evaluation to construction.

We expect our existing cash balances and operating cash flows will meet our anticipated capital requirements without the need for significant additional funding. Cash balances will decline as we use the funds in our business and pursue our growth plans.

Our outlook for 2012 reflects the growth 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 2011 Financial results by segment on page 10 for details.

2012 Financial outlook


	Production	- 21.7 million lbs 13 to 14 million kgU -
Sales volume	Sales volume	- 31 to 33 million lbs Decrease - 10% to 15%
	Capacity factor	- - - 95%
Revenue compared to 2011	Revenue compared to 2011	Decrease Decrease Decrease Increase 0% to 5% 0% to 5%1 10% to 15% 5% to 10%
	Average unit cost of sales	- Increase Increase Decrease 0% to 5%2 10% to 15% 5% to 10%
	(including D&A)
	Direct administration costs	Increase - - - 10% to 15%
	compared to 20113
	Exploration costs	- Increase - - 15% to 20%
	compared to 2011
Tax rate	Tax rate	Recovery of - - - 0% to 5%
	Capital expenditures	$620 million4 - - $80 million

1 Based on a uranium spot price of $52.00 (US) per pound (the Ux Consulting spot price as of February 6, 2012), a long-term price indicator of $61.00 (US) per pound (the Ux long-term indicator on January 30, 2012) and an exchange rate of $1.00 (US) for $1.00 (Cdn).

2 This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we decide to make discretionary purchases in 2012 then we expect the average unit cost of sales to increase further.

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

4 Does not include our share of capital expenditures at BPLP.

Consolidated outlook

We expect consolidated revenue to be 0% to 5% lower in 2012 due to:

lower sales volumes in the fuel services business
lower realized prices in the uranium business
partially offset by higher volumes in the electricity business

We expect administration costs (not including stock-based compensation) to be about 10% to 15% higher than in 2011 due to planned higher spending in support of our growth strategy.

We expect exploration expenses to be about 15% to 20% higher than they were in 2011 due to an increase in evaluation activities at Kintyre and Inkai block 3. We will also continue to focus efforts in Canada.

Uranium outlook

We expect to produce 21.7 million pounds in 2012. In addition, we have commitments under long-term contracts to purchase about 8 million pounds.

Based on the contracts we have in place, we expect to sell between 31 million and 33 million pounds of U3O8 in 2012. We expect the average unit cost of sales to be 0% to 5% higher than in 2011. The increase is due primarily to higher costs for produced material. If we decide to make additional discretionary purchases in 2012 then we expect the average unit cost of sales to increase further.

Based on current spot prices, revenue should be about 0% to 5% lower than it was in 2011 as a result of an expected decrease in the realized price.

Our customers choose when in the year to receive deliveries of uranium and fuel services products, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly. In 2012, we expect that deliveries will be evenly distributed across the quarters. However, not all delivery notices have been received to date, which could alter the delivery pattern.

Price sensitivity analysis: uranium

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, 2011 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, 2011, 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 each quarter. 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)

($US/lb UO) 3 8
Spot prices	$20	$40	$60	$80	$100	$120	$140

2012	38	42	50	57	66	74	81
2013	43	46	54	62	71	80	88
2014	45	48	56	65	74	83	91
2015	43	47	56	66	77	87	97
2016	45	50	58	68	78	88	97

The table illustrates the mix of long-term contracts in our December 31, 2011 portfolio, and is consistent with our contracting strategy. The table has been updated to December 31, 2011 to reflect:

deliveries made and contracts entered into up to December 31, 2011
changes to deliveries under some sales contracts to assist our customers who were directly impacted by the March nuclear incident in Japan
changes to deliveries under some contracts where deliveries are tied to reactor requirements

Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. We signed many of our current contracts in 2003 to 2005, when market prices were low ($11 to $31 (US)). Those that are fixed at lower prices or have low ceiling prices will yield prices that are lower than current market prices. These older contracts are beginning to expire, and we are starting to deliver into more favourably priced contracts.

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 Prices

sales volumes on average of 32 million pounds  the average long-term price indicator is the same per year as the average spot price for the entire year (a simplified approach for this purpose only). Since

Deliveries 1996, the long-term price indicator has averaged

customers take the maximum quantity allowed 14% higher than the spot price. This differential under each contract (unless they have already has varied significantly. Assuming the long-term provided a delivery notice indicating they will take price is at a premium to spot, the prices in the less)

table will be higher.

we defer a portion of deliveries under existing
- we deliver all volumes that we do not have

contracts for 2012 contracts for at the spot price for each scenario

Inflation

is 3% per year
5 -

Cameco’s share of production — annual forecast to 2016

We have geographically diverse sources of production. We are on track with our strategy to increase our annual production to 40 million pounds by 2018, which we expect will come from our operating properties, development projects and projects under evaluation.

	Current forecast	2012		2013	2014	2015	2016
	(million lbs)		2012
McArthur River/Key Lake			13.1	13.1 13.1 13.1 13.1
Rabbit Lake			3.7	3.7 3.7 3.7 3.4
US ISR			2.4	3.0 3.1 3.7 3.8
Inkai1			2.5	2.9 2.9 2.9 2.9
Cigar Lake			-	0.3 1.9 5.5 7.9
Total share of production			21.7	23.0 24.7 28.9 31.1
Cameco’s share of Inkai’s production on which profits are generated2
Inkai1			2.6	3.0 3.0 3.0 3.0
Total2			21.8	23.1 24.8 29.0 31.2

1 We have signed a memorandum of agreement (MOA) with Kazatomprom to increase annual production to 5.2 million pounds (100% basis). Once implemented, we will receive the right to purchase 2.9 million pounds of Inkai’s annual production and receive profits on 3.0 million pounds. See page 15 for more information.

2 We have adjusted the production table to reflect the share of Inkai’s production we will use to calculate our profits under the MOA. See page 15 for more information.

In 2013, production at McArthur River may be lower as we transition to mining upper zone 4.

Our 2012 and future annual production targets for Inkai assume, and we expect:

Inkai will obtain the necessary government permits and approvals to produce at an annual rate of 5.2 million pounds (100% basis), including an amendment to the resource use contract
we reach a binding agreement with Kazatomprom to finalize the terms of the MOA
Inkai will ramp up production to an annual rate of 5.2 million pounds (100% basis)

There is no certainty Inkai will receive these permits or approvals or we will reach a binding agreement with Kazatomprom or that Inkai will be able to ramp up production. If Inkai does not, or if the permits and approvals are delayed, Inkai may be unable to achieve its 2012 and future annual production targets and we may have to recatagorize some of Inkai’s mineral reserves as resources.

________________________

This forecast is forward-looking information. It is based on the assumptions and subject to the material risks discussed on pages 18 and 19 and specifically on the assumptions and risks noted above and listed on the following page. Actual production may be significantly different from this forecast.

Assumptions Material risks that could cause actual results to

we achieve our forecast production for each differ materially operation, which requires, among other things,  we do not achieve forecast production levels for that our mining plans succeed, processing plants each operation because of a change in our mining and equipment are available and function as plans, processing plants or equipment are not designed, we have sufficient tailings capacity and available or do not function as designed, lack of our mineral reserve estimates are reliable tailings capacity or for other reasons
we obtain or maintain the necessary permits and  we cannot obtain or maintain necessary permits or approvals from government authorities approvals from government authorities
our production is not disrupted or reduced as a  natural phenomena, labour disputes, political risks, result of natural phenomena, labour disputes, blockades or other acts of social or political political risks, blockades or other acts of social or activism, shortage or lack of supplies critical to political activism, shortage or lack of supplies production, equipment failures or other critical to production, equipment failures or other development and operation risks disrupt or reduce development and operation risks our production

Fuel services outlook

Due to current unfavourable market conditions for UF6 conversion, we are decreasing our production in 2012. We plan to produce between 13 million and 14 million kgU, and expect sales volumes in 2012 to be 10% to 15% lower than in 2011.

We are changing our fuel services product mix in 2012, producing and selling less UF6 than in 2011. We will also realize fewer 2012 cost recoveries in UF6 conversion. Therefore, in fuel services we expect:

the average realized price for our fuel services products to increase by 0% to 5%
revenue to decrease by 10% to 15%
average unit cost of sales (including depreciation and amortization (D&A)) to increase by 10% to 15%

Electricity outlook

Bruce Power estimates the average capacity factor for the four Bruce B reactors to be 95% in 2012, and actual output to be about 9% higher than it was in 2011 due to fewer planned outage days in 2012. The 2012 realized price for electricity is projected to be about the same as 2011. As a result, we expect that revenue will increase by 5% to 10%.

We expect the average unit cost of sales (net of cost recoveries) to be 5% to 10% lower in 2012 and total operating costs to decrease by about 0% to 5%, mainly due to fewer planned outages resulting in lower costs.

Capital spending

	(Cameco’s share in $ millions)	2011 plan	2011 actual		2012 plan
Growth capital
Cigar Lake 176			172	215
Inkai 9			1	10
McArthur River 14			24	35
Millennium 6			4	5
US ISR 13			15	30
Total growth capital 218			216	295
Sustaining capital
McArthur River/Key Lake 169			168	145
US ISR 38			39	50
Rabbit Lake 85			77	75
Inkai 19			15	30
Fuel services 32			18	20
Other 14			20	5
Total sustaining capital 357			337	325
Total uranium & fuel services 5751			553	620
Electricity (our 31.6% share of BPLP) 80			77	80

1 We updated our 2011 capital cost estimate in the Q1 MD&A to $620 million, in the Q2 MD&A to $590 million and in the Q3 MD&A to $575 million.

Capital expenditures were 4% below the updated guidance we provided in our third quarter MD&A, mainly due to variances at Inkai and in the fuel services division. We do not expect this reduction in capital expenditures in 2011 will impact our plans to increase annual uranium production by 2018. The variance at fuel services was mainly due to cancellation of certain projects and revisions to project schedules. The variance at Inkai was mainly due to the deferral of upgrades to infrastructure and slower than expected progress on approvals for block 3.

We expect total capital expenditures for uranium and fuel services to be about 12% higher in 2012 as a result of higher spending for:

growth capital at Cigar Lake
growth and sustaining capital at US ISR
sustaining capital at Inkai

In addition, we expect capital expenditures for 2013 and 2014 to be as follows:

($ millions) 2013 2014

Growth capital 325 – 350 250 – 275 Sustaining capital 325 – 350 350 – 375

Total uranium & fuel services 650 – 700 600 – 650

These growth capital expenditures are related to our Double U strategy. Many of these are early stage projects, however, and the mix of projects and their underlying capital estimates could change significantly. This is a preliminary estimate that we expect to fund using existing cash balances and operating cash flows.

________________________

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 factors discussed on pages 18 and 19. Our actual capital expenditures for future periods may be significantly different.

Sensitivity analysis

At December 31, 2011, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2011 net earnings by about $10 million (Cdn). This sensitivity is based on an exchange rate of $1.00 (US) for $1.02 (Cdn).

For 2012:

a change of $5 (US) per pound in each of the Ux spot price ($52.00 (US) per pound on February 6, 2012) and the Ux long-term price indicator ($61.00 (US) per pound on January 30, 2012) would change revenue by $68 million and net earnings by $55 million.
a change of $5/MWh in the electricity spot price would change our 2012 net earnings by $4 million based on the assumption that the spot price will remain below the floor price of $50.18/MWh provided for under BPLP’s agreement with the Ontario Power Authority (OPA).

Non-IFRS measures

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 earnings from discontinued operations. We also used this measure prior to adoption of IFRS (non-GAAP measure).

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

To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the fourth quarters of 2011 and 2010 and the years ended 2011 and 2010 as reported in our financial statements.

($ millions)	Three months ended			Year ended
	December 31			December 31
	2011		2010	2011		2010
Net earnings	265	206		450	516
Adjustments
Adjustments on derivatives1 (pre-tax)	(22)	(22)		80	(26)
Income taxes on adjustments to derivatives	6	6		(21)	7
Adjusted net earnings	249	190		509	497

1 In 2008, we opted to discontinue hedge accounting for our portfolio of foreign currency forward sales contracts. Since then, we have adjusted our gains and losses on derivatives as reported under IFRS to reflect what our earnings would have been had hedge accounting been applied.

2011 financial results by segment

Uranium

Highlights		Three months ended					Year ended
		December 31					December 31
		2011		2010	change		2011		2010	change
Production volume (million lbs)		6.6	6.4 3%				22.4	22.8 (2)%
Sales volume (million lbs)		13.8	9.1 52%				32.9	29.6 11%
Average spot price ($US/lb) Average long-term price ($US/lb) Average realized price ($US/lb) ($Cdn/lb)		51.79	58.29 (11)% 64.33 (3)% 48.51 7% 50.10 6%				56.36	46.83 20% 60.92 10% 43.63 13% 45.81 7%
		62.50					66.79
		52.09					49.17
		53.08					49.18
Average unit cost of sales ($Cdn/lb) (including D&A)	30.29	30.29	29.38 3%			29.94	29.94	27.87 7%
Revenue ($ millions)		731	457 60%				1,616	1,358 19%
Gross profit ($ millions)		314	189 66%				632	532 19%
Gross profit (%)		43	41 5%				39	39 -

Production volumes were 3% higher due to slightly higher output at Rabbit Lake and Inkai, partially offset by slightly lower output at McArthur River/Key Lake and Smith Ranch-Highland. See Operations and development project updates starting on page 14 for more information.

Uranium revenues were up 60% due to a 6% increase in the Canadian dollar average realized price, and a 52% increase in sales volumes.

Our realized prices this quarter were higher than the fourth quarter of 2010 mainly due to higher US dollar prices under market related contracts, partially offset by a less favourable exchange rate. In the fourth quarter of 2011, our realized foreign exchange rate was $1.02 compared to $1.03 in the prior year.

Total cost of sales (including D&A) increased by 56% ($417 million compared to $268 million in 2010). This was mainly the result of the following:

the 52% increase in sales volumes
higher royalty charges due to higher deliveries of Saskatchewan-produced material and higher realized prices
average unit costs for produced uranium were 2% higher
partially offset by 33% lower average unit costs for purchased uranium due to fewer purchases at spot prices

The net effect was a $125 million increase in gross profit for the quarter.

Full year

Production volumes in 2011 were 2% lower than 2010 due to lower production from Smith Ranch-Highland and Inkai. See Operations and development project updates starting on page 14 for more information.

Uranium revenues this year were up 19% compared to 2010, due to an 11% increase in sales volumes and an increase of 7% in the Canadian dollar average realized price. Sales volumes in 2011 were higher than 2010 due to some customers deferring 2010 deliveries under contracts until 2011. The 19% increase was higher than the guidance we provided in the third quarter (increase 10% to 15%) as sales volumes for 2011 were at the top of the range provided (31 million pounds to 33 million pounds) at that time.

10 -

Our realized prices this year in US dollars were 13% higher than 2010 mainly due to higher US dollar prices under market-related contracts. Our Canadian dollar selling price, however, was only 7% higher than 2010 as a result of a less favourable exchange rate when compared to 2010. Our exchange rate averaged $1.00 compared to $1.05 in 2010.

Total cost of sales (including D&A) increased by 19% this year ($983 million compared to $826 million in 2010). This was mainly the result of the following:

the 11% increase in sales volumes
average unit costs for produced uranium were 7% higher, although our average unit cost of sale for produced material was within the guidance we provided
average unit costs for purchased uranium were 14% higher due to the increase in spot prices
standby costs paid to AREVA relating to the McClean Lake mill
higher royalty charges due to higher deliveries of Saskatchewan-produced material and higher realized prices. In 2011, total royalties rose to $124 million from $78 million in 2010.

The net effect was a $100 million increase in gross profit for the year.

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

			Three months ended				Year ended December 31
			December 31
	($Cdn/lb)		2011		2010	change		2011		2010	change
Produced Cash cost Non-cash cost				15.94 9% 6.52 (15)%					16.89 9% 6.32 3%
			17.44					18.45
			5.52					6.50
Total production cost			22.96	22.46 2%				24.95	23.21 7%
Quantity produced (million lbs)			6.6	6.4 3%				22.4	22.8 (2)%
Purchased Cash cost				28.14 (33)%					22.85 14%
			18.86					26.08
Quantity purchased (million lbs)			2.3	4.3 (47)%				9.6	10.6 (9)%
Totals Produced and purchased costs				24.74 (11)%					23.10 9%
			21.90					25.29
Quantities produced and purchased (million lbs)		8.9	8.9	10.7 (17)%			32.0	32.0	33.4 (4)%

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 table below presents a reconciliation of these measures to our unit cost of sales for the fourth quarters of 2011 and 2010 and the years ended 2011 and 2010 as reported in our financial statements.

11 -

Cash and total cost per pound reconciliation

		Three months ended December 31			Year ended
					December 31
	($ millions)	2011		2010	2011	2010
Cost of product sold Add / (subtract) Royalties Standby charges Other selling costs Change in inventories		336.8	230.9 (18.2) (6.4) (7.9) 24.6		824.3	691.3
		(61.3)			(123.6)	(78.2)
		(6.0)			(22.0)	(12.0)
		(2.8)			(9.4)	(13.4)
		(108.2)			(5.7)	39.6
Cash operating costs (a) Add / (subtract) Depreciation and amortization Change in inventories		158.5	223.0 37.3 4.4		663.6	627.3
		80.1			159.2	134.9
		(43.7)			(13.6)	9.2
Total operating costs (b)		194.9	264.7		809.2	771.4
Uranium produced and purchased (millions lbs) (c)		8.9	10.7		32.0	33.4
Cash costs per pound (a ÷ c) Total costs per pound (b ÷ c)		17.81	20.84 24.74		20.74	18.78
		21.90			25.29	23.10

Fuel services results

(includes results for UF6, UO2 and fuel fabrication)

Highlights		Three months ended					Year ended
		December 31					December 31
		2011		2010	change		2011		2010	change
Production volume (million kgU)		3.1	3.9 (21)%				14.7	15.4 (5)%
Sales volume (million kgU)		7.2	6.3 14%				18.3	17.0 8%
Realized price ($Cdn/kgU)		14.66	14.59 -				16.71	16.86 (1)%
Average unit cost of sales ($Cdn/kgU) (including D&A)	11.18	11.18	12.49 (10)%			13.75	13.75	13.05 5%
Revenue ($ millions)		106	91 16%				305	287 6%
Gross profit ($ millions)		25	13 92%				54	65 (17)%
Gross profit (%)		24	14 71%				18	23 (22)%

Fourth quarter

Production volumes were 21% lower than in 2010 due to the decrease in production of UF6. We reduced our production forecast in the third quarter as a result of unfavourable market conditions.

Total revenue increased by 16% due to a 14% increase in sales volumes and a slight increase in realized price.

The total cost of sales (including D&A) increased by 4% ($81 million compared to $78 million in the fourth quarter of 2010) due to the increase in sales volumes. When compared to 2010, the average unit cost of sales was 10% lower primarily due to higher cost recoveries in 2011.

The net effect was a $12 million increase in gross profit.

12 -

← Back to feed