This management's discussion and analysis (MD&A) includes information that will help you understand management's perspective of our unaudited consolidated financial statements and notes for the quarter ended March 31, 2010. The information is based on what we knew as of May 3, 2010 and updates the annual MD&A included in our 2009 annual report.

As you review the MD&A, we encourage you to read our unaudited consolidated financial statements and notes for the period ended March 31, 2010 as well as our audited consolidated financial statements and notes for the year ended December 31, 2009 and annual MD&A of the audited financial statements. You can find more information about Cameco, including our audited consolidated financial statements and our most recent annual information form, on this website, on SEDAR at sedar.com or on EDGAR at sec.gov. You should also read our annual information form before making a decision to invest in our securities.

Unless we have specified otherwise, all dollar amounts are in Canadian dollars. The financial information in this MD&A and in our financial statements and notes are prepared according to Canadian generally accepted accounting principles (Canadian GAAP), unless otherwise indicated. We also prepared a reconciliation of our annual financial statements to US GAAP, which has been filed with securities regulatory authorities.

About forward-looking information

Our MD&A includes statements and information about our expectations for the future. When we discuss our strategy, plans and 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 MD&A as forward-looking information.

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

• It typically includes words and phrases about the future, such as: anticipate, expect, plan, intend, predict, goal, target, project, potential, strategy and outlook (see examples).
• It represents our current views, and can change significantly.
• It is based on a number of material assumptions, including those we've 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 below. We recommend you also review our annual information form and our 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 MD&A

• production at our uranium operations from 2010 to 2014 and our target for doubling annual production by 2018
• our expectation that the demand for uranium will continue to grow and that there will be a need for new supply to meet future customer requirements
• our expectation that we will complete the Key Lake acid, steam and oxygen plants in 2011
• our mid-2013 target for initial production from Cigar Lake and our 2010 Cigar Lake plans
• our expectation that we will invest significantly in expanding production at our existing mines and advancing projects as we pursue our growth strategy
• our expectations that our existing cash balances and operating cash flows will meet our anticipated requirements over the next several years without the need for any significant additional financing
• our expectation that the removal of the abandoned freezepipes will no longer pose a risk to 2010 McArthur River production
• our expectation that our operating and investment activities in 2010 will not be constrained by the financial covenants in our general credit facilities
• the expected impact on the uranium market of the developments discussed under Uranium market update
• our estimate that royalties will reduce net earnings by between $35 million and $40 million in 2010
• our uranium price sensitivity analysis
• the outlook for each of our operating segments for 2010, and our consolidated outlook for the year
• our expectation that uranium and fuel services deliveries will be more heavily weighted to the second and fourth quarters of 2010
• our expectation that the momentum behind nuclear energy will continue to grow and so will our success
• our forecast of 2010 uranium long-term contracting to be in the order of 100 million pounds

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
• production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms
• our estimates of production, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate
• we are unable to enforce our legal rights, or are subject to litigation or arbitration that has an adverse outcome
• there are defects in title to our properties
• our reserve and resource estimates are inaccurate, or we face unexpected or challenging geological, hydrological or mining conditions
• we are affected by environmental, safety and regulatory risks, including increased regulatory burdens
• we cannot obtain or maintain necessary permits or approvals from government authorities
• we are affected by political risks in a developing country where we operate (like Kazakhstan)
• we are affected by terrorism, sabotage, accident or a deterioration in political support for, or demand for, nuclear energy
• there are changes to government regulations or policies, including tax and trade laws and policies
• our uranium and conversion suppliers fail to fulfil delivery commitments
• delay or lack of success in remediating and developing Cigar Lake
• 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, labour relations issues, strikes or lockouts, underground floods, pitwall failure, cave-ins and other developments and operating risks

Material assumptions

• sales and purchase volumes and prices for uranium, fuel services and electricity
• expected production costs
• expected spot prices and realized prices for uranium, and other factors discussed here, Price sensitivity analysis: uranium
• tax rates, foreign currency exchange rates and interest rates
• decommissioning and reclamation expenses
• reserve and resource estimates
• the geological, hydrological and other conditions at our mines, including the accuracy of our expectations about the condition of underground workings at Cigar Lake
• our Cigar Lake remediation and development plans succeed
• 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, natural disasters, governmental or political actions, litigation or arbitration proceedings, labour relations issues, or other development or operating risks

First quarter update

Cameco is well positioned as the world becomes increasingly focused on nuclear as a source of clean, reliable and affordable energy. We are among the world's largest players in a market where demand is growing.

Our vision is to be a dominant nuclear energy company producing uranium fuel and generating clean electricity. We are already one of the largest uranium producers in the world, and when we sold our gold segment late last year, became a pure-play nuclear energy investment.

Our strategy is to double annual uranium production to 40 million pounds by 2018, which we plan to accomplish with our existing operating and development properties, and other projects already in our portfolio. Our fuel services segment is helping to support this growth by broadening our business relationships and expanding our uranium market share. And our investment in the Bruce Power Limited Partnership is an excellent source of earnings and cash flow.

You can read more about our strategy in our 2009 annual MD&A.

We are in the fortunate position of having the financial strength to advance our growth plans. In our 2009 annual MD&A we talked about our plans to increase expenditures, both capitalized and expensed, to achieve our growth strategy. We are steadfastly focused on the long-term, spending prudently today for greater benefit tomorrow.

A great start to the year

Net earnings this quarter were 73% higher than they were in the same quarter of 2009. This was mainly due to $31 million in after-tax profit we recorded this quarter for unrealized mark-to-market gains on financial instruments. Adjusted net earnings were 8% higher.

Revenues were 2% lower than in the first quarter of 2009 due to lower sales volumes and slightly lower Canadian dollar realized prices in our uranium segment. Our realized prices were impacted by a stronger Canadian dollar ($US realized prices increased 15%). Higher sales volumes in fuel services, and higher realized prices in electricity, partially offset the impact of the uranium segment.

Highlights March 31 ($ millions except where indicated)				Three months ended
				March 31
				2010	2009	change
Revenue				485	493	(2)%
Gross profit				180	161	12%
Net earnings				142	82	73%
$ per common share (diluted)				0.36	0.22	64%
Adjusted net earnings (non-GAAP)				111	103	8%
$ per common share (adjusted and diluted)				0.28	0.27	4%
Cash provided by continuing operations				133	180	(26)%
Average realized prices		Uranium	$US/lb	42.34	36.71	15%
			$Cdn/lb	45.79	46.72	(2)%
		Fuel services	$Cdn/kgU	26.06	26.29	(1)%
		Electricity	$Cdn/MWh	58.00	52.00	12%

In our uranium segment this quarter, we increased production by 27% compared to the first quarter of 2009, as production at almost all our sites increased. Some key highlights:

• McArthur River performed better than planned during the quarter. The zone 4 transition is ahead of schedule and we no longer expect the removal of abandoned freezepipes to pose a production risk in 2010.
• At Inkai, completion of the processing facilities and a stable acid supply resulted in higher production than in the first quarter of 2009.
• We made progress on our work to secure the underground development at Cigar Lake this quarter, and are carrying out plans and implementing strategies to achieve our mid-2013 target for initial production.

In our fuel services segment, the Port Hope UF₆ plant was fully operational and we increased production over the first quarter of 2009 by 129%.

Global Laser Enrichment (GLE) successfully completed initial testing of its enrichment technology, which met key enrichment performance criteria. GLE has indicated it will continue testing and begin focusing on the design of the first commercial production facility. If the technology is successful and a commercial facility is completed, it will use lasers to commercially enrich uranium.

In our electricity segment, BPLP generated 6.8 terawatt hours (TWh) of electricity, at a capacity factor of 98%.

Highlights March 31		Three months ended
		March 31
		2010	2009	change
Uranium	Production volume (million lbs)	6.1	4.8	27%
	Sales volume (million lbs)	6.6	7.1	(7)%
	Revenue ($ millions)	305	336	(9)%
Fuel services	Production volume (million kgU)	4.8	2.1	129%
	Sales volume (million lbs)	2.2	1.9	16%
	Revenue ($ millions)	60	54	11%
Electricity	Output (100%) (TWh)	6.8	6.8	–
	Revenue (100%)	394	355	11%
	Our share of earnings before taxes ($ millions)	54	44	23%

Shares and stock options outstanding
At April 30, 2010, we had:

• 392,975,635 common shares and one Class B share outstanding
• 9,284,885 stock options outstanding, with exercise prices ranging from $5.75 to $55.00

Dividend policy
Our board of directors has established a policy of paying a quarterly dividend of $0.07 ($0.28 per year) per common share. This policy will be reviewed from time to time based on our cash flow, earnings, financial position, strategy and other relevant factors.

Uranium market update

There are several things of note this quarter.

The US and Russia announced the signing of a new nuclear arms control treaty. If the treaty is ratified by lawmakers in both countries, it will mandate a reduction in their arsenals. While it is expected this will result in weapons being taken out of active service, there has been no commitment to dismantle nuclear weapons and no discussion of commercializing the contained uranium. We do not expect the new treaty will have any impact on the uranium market.

The US also hosted a Nuclear Security Summit in mid April, where many countries announced that they were taking action to secure nuclear materials around the globe. Many of these announcements are not new to the nuclear industry. In fact, the commitment by the US and Russia to each dispose of 34 tonnes of surplus weapons grade plutonium has been under discussion for many years and we have included this supply source in our forecast of secondary supplies since the late 1990's. Both the US and Russia have been importing fresh and spent highly enriched uranium from many countries for a number of years. In the US, this is carried out by the National Nuclear Security Administration and a portion of this product is included in the excess US Department of Energy (DOE) inventories. These inventories, which are already included in supply forecasts, are not expected to enter the market at a rate of greater than about 5 million pounds per year.

In 2009, the DOE announced it would use its uranium inventories to pay for certain services. As payment in 2010, it plans to transfer about 2.4 million pounds U₃O₈ equivalent to the United States Enrichment Corporation (USEC). USEC has already sold about 0.5 million pounds U₃O₈ equivalent into the spot market. Early in 2010, the DOE asked for budget funds in future years to pay for these services directly, noting its statutory obligation not to adversely impact the uranium market. It is possible however, that Congress will elect not to provide the funds as requested.

Industry prices

		Mar 31 2010	Dec 31 2009	Mar 31 2009	Dec 31 2008
Uranium ($US/lb U3O8)1
Average spot market price		41.88	44.50	42.00	52.50
Average long-term price		59.00	61.00	69.50	70.00
Fuel services ($US/kgU UF6)1
Average spot market price
	- North America	5.63	5.75	8.50	8.50
	- Europe	7.50	8.00	9.75	9.75
Average long-term price
	- North America	11.00	11.00	12.25	12.25
	- Europe	12.75	12.75	13.38	13.38
Note: the industry does not publish UO2 prices.
Electricity ($/MWh)
Average Ontario electricity spot price		34.00	30.00	43.00	49.00
1 Average of prices reported by TradeTech and Ux Consulting (Ux)

On the spot market, where purchases call for delivery within one year, the volume reported for the first quarter of 2010 was about 12.9 million pounds U₃O₈. This compares to about 8 million pounds in the first quarter of 2009.

Notwithstanding the increased volume, spot uranium prices continued to trend down this quarter, decreasing in January and February, with only a slight rise in March. Since the end of the quarter, prices have decreased, with Ux reporting $41.75 on May 3, 2010. Demand in the spot market has been extremely discretionary, as buyers are moving in and out as the price changes.

Long-term uranium prices declined during the quarter as some sellers lowered their base price to conclude sales. Term contracting activity has been very limited and we now anticipate long-term contracting in 2010 will be in the order of 100 million pounds, down from 150 million pounds estimated earlier this year. However this level could be significantly higher if demand arises from emerging markets. Long-term contracts usually call for deliveries to begin more than two years after the contract is finalized, and use a number of pricing formulas, including fixed prices adjusted by inflation indices, and market referenced prices (spot and long-term indicators).

Utilities are well covered under existing contracts and have been building inventory levels of U₃O₈ since 2004, so we expect uranium demand in the near term to remain very discretionary.

Spot market UF₆ conversion prices continued to decline during the quarter, although at a slower rate than in the fourth quarter of 2009. Long-term market UF₆ conversion prices were stable this quarter.

Long-term fundamentals are strong

People need electricity regardless of world economic conditions, and nuclear power is an affordable and sustainable source of clean, reliable energy. The demand for uranium is expected to continue to grow, and along with it, the need for new supply to meet future customer requirements.

Cameco's long history of success comes from many years of hard work and discipline, developing and acquiring the expertise and assets that position us well to deliver on our strategy. As the momentum behind nuclear energy continues to grow, so will our success.

Financial results

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

Consolidated financial results

In 2009, we sold all of our shares of Centerra Gold Inc. (Centerra).

For comparison purposes, we have recast our consolidated financial results for the first quarter of 2009 to show the impact of Centerra as a discontinued operation, which is required under Canadian GAAP. The change affected a number of financial measures, including revenue, gross profit, administration costs and income tax expense. See note 12 to the financial statements for more information.

Highlights ($ millions except per share amounts)		Three months ended
		March 31
		2010	2009	change
Revenue		485	493	(2)%
Net earnings		142	82	73%
	$ per common share (basic)	0.36	0.22	64%
	$ per common share (diluted)	0.36	0.22	64%
Adjusted net earnings (non-GAAP)		111	103	8%
	$ per common share (adjusted and diluted)	0.28	0.27	4%
Cash provided by operations (after working capital changes)		133	180	(26)%

The tables that follow describe what contributed to the changes this quarter.

Revenue 2% lower

($ millions)
Revenue – three months ended March 31, 2009		493
Changes:
	Uranium business – lower sales volumes; lower realized prices ($Cdn)	(28)
	Fuel services business – higher sales volumes	8
	Electricity business – higher realized prices	12
Revenue – three months ended March 31, 2010		485

See Financial results by segment for more detailed discussion.

Average realized prices

		Three months ended
		March 31, 2010
		2010	2009	change
Uranium	$US/lb	42.34	36.71	15%
	$Cdn/lb	45.79	46.72	(2)%
Fuel services	$Cdn/kgU	26.06	26.29	(1)%
Electricity	$Cdn/MWh	58.00	52.00	12%

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. We expect the trend in delivery patterns in 2010 to be similar to 2009, with deliveries more heavily weighted to the second and fourth quarters.

Gross profit up 12%

We calculate gross profit by deducting the cost of products and services sold, and depreciation, depletion and reclamation (DDR), from revenue.

($ millions)
Gross profit – three months ended March 31, 2009		161
Changes:
	Uranium business – lower sales volumes; lower realized prices ($Cdn)	(14)
	Fuel services business – higher sales volumes; higher production	15
	Electricity business – higher realized prices	15
	Other	3
Gross profit – three months ended March 31, 2010		180

See Financial results by segment for more detailed discussion.

Net earnings up 73%

Our net earnings this quarter were $60 million higher than the same quarter in 2009. This was mainly due to $31 million in after-tax profit that we recorded this quarter for unrealized mark-to-market gains on financial instruments, compared to a loss of $24 million in the first quarter of 2009.

Adjusted net earnings up 8%

(non-GAAP, see below)

($ millions)
Adjusted net earnings – three months ended March 31, 2009		103
Changes:
	Uranium business – lower sales volumes; lower realized prices ($Cdn)	(14)
	Fuel services business – higher sales volumes; higher production	15
	Electricity business – higher realized prices	15
	Income tax expense	(25)
	All other	17
Adjusted net earnings – three months ended March 31, 2010		111

A note about non-GAAP measures

We use adjusted net earnings, a non-GAAP measure, as a more meaningful way to compare our financial performance from period to period. Adjusted net earnings is our GAAP-based net earnings adjusted for one-time costs, writedowns, gains and unrealized mark-to-market losses on our financial instruments, which we believe do not reflect underlying performance.

Adjusted net earnings is non-standard supplemental information, and not a substitute for financial information prepared according to GAAP. Other companies may calculate this measure differently. The table below reconciles adjusted net earnings with our net earnings.

($ millions)		Three months ended
		March 31
		2010	2009
Net earnings (GAAP measure)		142	82
Adjustments (after tax)
	Earnings from discontinued operations	–	(3)
	Unrealized losses (gains) on financial instruments	(31)	24
Adjusted net earnings (non-GAAP measure)		111	103

Quarterly trends

Highlights ($ millions except per share amounts)		2010	2009				2008
		Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Revenue		485	659	518	645	493	640	329	620
Net earnings		142	598	172	247	82	31	136	150
	$ per common share (basic)	0.36	1.52	0.44	0.65	0.22	0.08	0.39	0.44
	$ per common share (diluted)	0.36	1.52	0.44	0.64	0.22	0.08	0.39	0.43
Adjusted net earnings (non-GAAP)		111	169	94	162	103	179	128	139
	$ per share diluted	0.28	0.43	0.24	0.41	0.27	0.49	0.37	0.39
Earnings from continuing operations		142	174	195	270	78	5	124	108
	$ per common share (basic)	0.36	0.44	0.49	0.70	0.21	0.01	0.37	0.31
	$ per common share (diluted)	0.36	0.44	0.49	0.70	0.21	0.01	0.37	0.30
Cash provided by operations		133	188	175	161	180	224	87	100

Key things to note:

• Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 63% of consolidated revenues in the first quarter of 2010.
• The timing of customer requirements, which tend to vary from quarter to quarter, drives revenue in the uranium and fuel services segments. In 2010, uranium sales volumes are expected to be most heavily weighted to the second and fourth quarters – similar to 2009.
• Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-GAAP measure, as a more meaningful way to compare our results from period to period (more information).
• Cash from operations tends to fluctuate as a result of the timing of deliveries and product purchases in our uranium and fuel services segments (more information).
• Quarterly results are not necessarily a good indication of annual results due to the variability in customer requirements noted above.

Exploration

Uranium exploration expenses were $15 million this quarter compared to $10 million in the same quarter in 2009, as activity in Canada and at the Kintyre project in Australia increased. Exploration in 2010 is focused on Canada, the United States, Mongolia, Kazakhstan, Australia and South America.

Gains and losses on derivatives

We recorded $43 million in mark-to-market gains on our financial instruments this quarter, compared to losses of $29 million in the first quarter of 2009: the Canadian dollar was much stronger this quarter – our exchange rate averaged $1.08 compared to $1.27 a year ago. We voluntarily removed the hedging designation on our foreign currency forward sales contracts in 2008 and have since recognized unrealized mark-to-market gains and losses in earnings.

Income taxes

We recorded an income tax expense of $25 million this quarter compared to a recovery of $21 million in the first quarter of 2009. The expense this quarter was mainly due to a $109 million increase in pretax earnings, which was largely attributable to the $43 million we recorded in gains on derivatives. In the first quarter of 2009 we recorded losses of $29 million.

Our effective tax rate in this quarter on an adjusted net earnings basis was 11%, 24% higher than in the first quarter of 2009 when we recorded a net recovery of income tax expenses. We earned a higher proportion of taxable income in jurisdictions with higher tax rates this quarter.

Foreign exchange

At March 31, 2010:

• The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.02 (Cdn), down from $1.00 (US) for $1.05 (Cdn) at December 31, 2009. The exchange rate averaged $1.00 (US) for $1.04 (Cdn) over the quarter.
• Our effective exchange rate for the quarter, after allowing for hedging, was about $1.08, compared to $1.27 in the first quarter of 2009.
• We had foreign currency contracts of $1.5 billion (US) and EUR 35 million at March 31, 2010. The US currency contracts had an average exchange rate of $1.00 (US) for $1.06 (Cdn).
• The mark-to-market gain on all foreign exchange contracts was $59 million compared to a $67 million gain at December 31, 2009.

Timing differences between the maturity dates and designation dates on previously closed hedge contracts can result in deferred gains or charges. At March 31, 2010, we had net deferred gains of $31 million. The table below shows when we will recognize the gains in earnings.

$ millions (Cdn)	2010	2011
Deferred gains (charges)	26	5

Sensitivity analysis

At March 31, 2010, every one-cent change in the value of the Canadian dollar versus the US dollar would change our net earnings by about $11 million (Cdn). This sensitivity is based on an exchange rate of $1.00 (US) for $1.02 (Cdn).

Outlook for 2010

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, based on current uranium spot prices, will meet our anticipated requirements over the next several years, without the need for significant additional funding. Our cash balances will decline gradually as we use the funds to pursue our growth plans.

Our outlook for 2010 reflects the growth expenditures necessary to help us achieve our strategy. Our outlook is unchanged from the outlook included in our annual MD&A. We do not include an outlook for the items in the table that are marked with a dash.

See Financial results by segment for details.

	Consolidated	Uranium	Fuel services	Electricity
Production	–	21.5 million lbs	14 to 16 million kgU	–
Sales volume	–	31 to 33 million lbs	Increase 15% to 20%	–
Capacity factor	–	–	–	About 90%
Revenue compared to 2009	Decrease 5% to 10%	Decrease 5% to 10%1	Increase 5% to 10%	Decrease 5% to 10%
Unit cost of product sold (including DDR)	–	Decrease 5% to 10%2	–	Increase 10% to 15%
Direct administration costs compared to 20093	Increase 25% to 30%	–	–	–
Exploration costs compared to 2009	–	Increase 80% to 90%	–	–
Tax rate	Less than 5%	–	–	–
Capital expenditures	$552 million4	–	–	$41 million
1 Based on a uranium spot price of $41.75 (US) per pound (the Ux spot price as of May 3, 2010) and an exchange rate of $1.00 (US) for $1.02 (Cdn). 2 Assumes the unit cost of sale for produced material will decline by 2% to 5% and the unit cost of sale for purchased material will decline by 15% to 20%. 3 Direct administration costs do not include stock-based compensation expenses. 4 Does not include our share of capital expenditures at BPLP.

Sensitivity analysis

For the rest of 2010:

• a change of $5 (US) from the Ux spot price on May 3, 2010 ($41.75 (US) per pound) would change revenue by $31 million and net earnings by $20 million
• a change of $1 in the electricity spot price would change our 2010 net earnings by $2 million, based on the assumption that the spot price will remain below the floor price provided for under BPLP's agreement with the Ontario Power Authority (OPA)

Liquidity and capital resources

Cash from operations

Cash from operations was $47 million lower than in 2009 due to much greater working capital requirements. In the first quarter of 2010, working capital consumed $71 million, primarily from a decrease in accounts payable, whereas in 2009, working capital provided $87 million in cash largely due to a decrease in receivables. Not including working capital requirements, our operating cash flows were higher in 2010 mainly due to higher cash margins in our fuel services and electricity businesses.

Debt

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $1.1 billion at March 31, 2010, compared to $1.2 billion at December 31, 2009. Our short-term borrowing and letters of credit facilities decreased by about $50 million during the quarter. At March 31, 2010, we had approximately $542 million outstanding in letters of credit.

Credit ratings

Third-party ratings for our commercial paper and senior debt as of March 31, 2010:

Security	DBRS	S&P
Commercial paper	R-1 (low)	A-1 (low)1
Senior unsecured debentures	A (low)	BBB+
1 Canadian National Scale Rating. The Global Scale Rating is A-2.

Debt covenants

We are bound by certain covenants in our general credit facilities. The financially related covenants place restrictions on total debt, including guarantees, and set minimum levels of net worth. As at March 31, 2010, we met these financial covenants and do not expect our operating and investment activities in 2010 to be constrained by them.

Long-term contractual obligations and off-balance sheet arrangements

There have been no material changes to our long-term contractual obligations, purchase commitments and financial assurances since December 31, 2009, including payments due for the next five years and thereafter. Please see our annual MD&A for more information.

Balance sheet

($ millions except per share amounts)	Mar 31, 2010	Dec 31, 2009	change
Cash and short-term investments	1,318	1,304	1%
Total debt	1,036	1,041	–
Inventory	468	453	3%

Total cash and short-term investments at March 31, 2010 were $1.3 billion, 1% higher than at December 31, 2009, and exceeding our total debt by $282 million.

Total product inventories increased by 3% to $468 million this quarter as fuel services inventory was higher. Uranium inventory was down slightly since sales were marginally higher than production and purchases during the quarter.

Financial results by segment

Uranium

Highlights		Three months ended
		March 31
		2010	2009	change
Production volume (million lbs)		6.1	4.8	27%
Sales volume (million lbs)		6.6	7.1	(7)%
Average spot price ($US/lb)		41.79	44.67	(6)%
Average realized price
	($US/lb)	42.34	36.71	15%
	($Cdn/lb)	45.79	46.72	(2)%
Cost of sales ($Cdn/lb U3O8) (including DDR)		29.81	30.20	(1)%
Revenue ($ millions)		305	336	(9)%
Gross profit ($ millions)		102	116	(12)%
Gross profit (%)		33	34	(3)%

Production volumes were 27% higher this quarter compared to the first quarter of 2009, as production at McArthur River, Rabbit Lake, Smith Ranch-Highland and Inkai was higher. See Operating properties for more information.

Uranium revenues were down 9% compared to the first quarter of 2009 due to a 7% decline in sales volumes and a 2% decrease in our $Cdn realized price: the Canadian dollar was much stronger this quarter – our exchange rate averaged $1.08 compared to $1.27 a year ago. In $US, our realized price for the quarter was 15% higher than in the first quarter of 2009 mainly due to stronger prices under fixed-price sales contracts.

Total cash cost of sales (excluding DDR) decreased by 13% this quarter, to $167 million ($25.14 per pound U₃O₈). This was mainly the result of the following:

• a 7% decline in sales volume
• average costs for produced uranium were lower due to higher production levels
• we delivered a lower proportion of purchased material, which carries a higher cost than our produced uranium

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

The following table shows our cash cost of sales per unit (excluding DDR) for produced and purchased material, including royalty charges on produced material, as well as the amounts of produced and purchased uranium sold.

Three months ended March 31	Unit cash cost of sale			Quantity sold
	($Cdn/lb U3O8)			(million lbs)
	2010	2009	change	2010	2009	change
Produced	24.22	25.14	(0.92)	4.6	4.2	0.4
Purchased	27.26	29.45	(2.19)	2.0	2.9	(0.9)
Total	25.14	26.89	(1.75)	6.6	7.1	(0.5)

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.

The table has been updated to reflect deliveries made and contracts entered into up to March 31, 2010. It is designed to indicate how the portfolio of long-term contracts we had in place on March 31, 2010 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 March 31, 2010, and none of the assumptions listed below change.

Expected realized uranium price sensitivity under various spot price assumptions
(rounded to the nearest $1.00)

($US/lb U3O8)
Spot prices	$20	$40	$60	$80	$100	$120	$140
2010	37	40	46	50	55	60	64
2011	33	38	47	54	62	70	78
2012	36	40	49	58	67	76	85
2013	43	46	56	65	76	86	95
2014	42	46	57	67	79	90	99

In the table, our average realized price increases over time under all spot price scenarios. This illustrates the mix of long-term contracts in our March 31, 2010 portfolio, and is consistent with our contracting strategy.

Our contracts usually include a mix of fixed-price and market-price components, 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 to create the table:

Sales

• sales volume of 32 million pounds in 2010 (the midpoint of our outlook for the year)
• sales volume of 30 million pounds for 2011 and every year following

Deliveries

• customers take the maximum quantity allowed under each contract (unless they have already provided a delivery notice indicating they will take less)
• we defer a portion of deliveries under existing contracts for 2010, 2011 and 2012

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)
• we deliver all volumes that we don't have contracts for at the spot price for each scenario

Inflation

• is 2.0% per year

Tiered royalties

The following table provides the updated rates for 2010 Saskatchewan tiered royalty calculations on the sale of uranium extracted from our Saskatchewan mines.

The tiered royalty is calculated on the positive difference between the sales price per pound of U₃O₈ and the prescribed prices according to the following:

Royalty rate	Canadian dollar sales price in excess of:
6%	$17.51
Plus 4%	$26.27
Plus 5%	$35.03

For example, if Cameco realized a sales price of $40 per pound in Canadian dollars, tiered royalties would be calculated as follows (assuming all capital allowances have been reduced to zero):

   [6% x ($40.00 – $17.51) x pounds sold]
+ [4% x ($40.00 – $26.27) x pounds sold]
+ [5% x ($40.00 – $35.03) x pounds sold]
= $2.15 per pound sold (about 5.4% of the assumed $40 contract price)

We estimate that tiered royalties will reduce net earnings by between $35 million and $40 million in 2010. We will be eligible for additional capital allowances once Cigar Lake begins production, at which time we will not pay tiered royalties until the additional allowances are fully exhausted.

Fuel services

(includes results for UF₆, UO₂ and fuel fabrication)

Highlights	Three months ended
	March 31
	2010	2009	change
Production volume (million kgU)	4.8	2.1	129%
Sales volume (million kgU)	2.2	1.9	16%
Realized price ($Cdn/kgU)	26.06	26.29	(1)%
Cost of sales ($Cdn/kgU) (including DDR)	16.30	22.41	(27)%
Revenue ($ millions)	60	54	11%
Gross profit ($ millions)	22	7	214%
Gross profit (%)	37	14	164%

The Port Hope UF₆ conversion plant was fully operational this quarter. It had been shut down during the first quarter of 2009. Total revenue rose by 11% due to higher sales volumes.

The cost of products and services sold (including DDR) declined by 17% ($38 million compared to $46 million in the first quarter of 2009). The unit cost of sales was also significantly lower as we allocated costs related to the UF₆ plant to inventory this quarter. In the first quarter of 2009 we expensed these costs, due to the plant shutdown.

The net effect was a $15 million increase in gross profit.

Electricity

BPLP

(100% – not prorated to reflect our 31.6% interest)

Highlights March 31 ($ millions except where indicated)		Three months ended
		March 31
		2010	2009	change
Output - terawatt hours (TWh)		6.8	6.8	–
Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)		98%	97%	1%
Realized price ($/MWh)		58	52	12%
Average Ontario electricity spot price ($/MWh)		34	43	(21)%
Revenue		394	355	11%
Operating costs (net of cost recoveries)		213	207	3%
	Cash costs	178	175	2%
	Non-cash costs	35	32	9%
Income before interest and finance charges		181	148	22%
Interest and finance charges		7	1	600%
Cash from operations		165	102	62%
Capital expenditures		17	12	42%
Distributions		150	105	43%
Operating costs ($/MWh)		31	30	3%

Our earnings from BPLP

Highlights March 31 ($ millions except where indicated)	Three months ended
	March 31
	2010	2009	change
BPLP's earnings before taxes (100%)	174	147	18%
Cameco's share of pretax earnings before adjustments (31.6%)	55	46	20%
Proprietary adjustments	(1)	(2)	50%
Earnings before taxes from BPLP	54	44	23%

Total electricity revenue increased by 11% this quarter compared to the first quarter of 2009 mainly due to higher realized prices, which reflect spot sales, revenue recognized under BPLP's agreement with the OPA and financial contract revenue. BPLP recognized revenue of $103 million this quarter under its agreement with the OPA. The equivalent of about 22% of BPLP's output was sold under financial contracts this quarter, compared to 64% in the first quarter of 2009.

The capacity factor was 98% this quarter, up from 97% in the first quarter of 2009. Operating costs were $213 million compared to $207 million in 2009.

The result was a 23% increase in our share of earnings before taxes.

BPLP distributed $150 million to the partners in the first quarter. Our share was $47 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.

Our operations and development projects

Uranium – production overview

We increased production by 27% this quarter compared to the first quarter of 2009 as production at almost all our sites increased. Key highlights:

• McArthur River performed better than planned. The zone 4 transition is ahead of schedule and we no longer expect the removal of abandoned freezepipes to pose a production risk in 2010.
• At Inkai, completion of the processing facilities and a stable acid supply resulted in higher production than in the first quarter of 2009.

Uranium production

Cameco's share (million lbs U3O8)	Three months ended
	March 31
	2010	2009	2010 plan
McArthur River/Key Lake	3.7	3.6	13.1
Rabbit Lake	1.0	0.5	3.6
Smith Ranch-Highland	0.5	0.4	1.8
Crow Butte	0.2	0.2	0.7
Inkai	0.7	0.1	2.3
Total	6.1	4.8	21.5

Outlook

Our sources of production are diversified both geographically and geologically. As outlined below, we expect production to total 115.9 million pounds of U₃O₈ over the next five years. Our strategy is to double our annual production to 40 million pounds by 2018, which we expect will come from our operating properties, development projects and other projects already in our portfolio.

Cameco's share of production — annual forecast to 2014

Current forecast (million lbs U3O8)	2010	2011	2012	2013	2014
McArthur River/Key Lake	13.1	13.1	13.1	13.1	13.1
Rabbit Lake	3.6	3.6	3.6	3.6	3.0
US ISR	2.5	2.6	3.0	3.4	3.8
Inkai	2.3	3.1	3.1	3.1	3.1
Cigar Lake	–	–	–	1.0	2.0
Total	21.5	22.4	22.8	24.2	25.0

We expect Inkai to produce 5.2 million pounds of U₃O₈ per year by 2011 (our share 3.1 million pounds).

Inkai has regulatory approval to produce 2.6 million pounds (100% basis). It has applied for regulatory approval to increase production to 3.9 million pounds in 2010 (100% basis) and will seek approval to produce at an annual rate of 5.2 million pounds in future years.

We expect Inkai to receive the permits and approvals it requires to support these production plans.

This forecast is forward-looking information. It is based on the assumptions and subject to the material risks, and specifically on the assumptions and risks listed here. Actual production may be significantly different from this forecast.

Assumptions

• we achieve our forecast production for each operation, which requires, among other things, that our mining plans succeed, Cigar Lake remediation and development plans succeed, processing plants function and our reserve estimates are accurate
• we obtain or maintain the necessary permits and approvals from government authorities
• our production is not disrupted or reduced as a result of natural phenomena, labour disputes, political risks, shortage or lack of supplies critical to production, equipment failures or other development and operation risks

Material risks that could cause actual results to differ materially

• we do not achieve forecast production levels for each operation due to a change in our mining plans, delay or lack of success in remediating and developing Cigar Lake, processing plant availability, lack of tailings capacity or for other reasons
• we cannot obtain or maintain necessary permits or government approvals
• natural phenomena, labour disputes, political risks, shortage or lack of supplies critical to production, equipment failures or other development and operation risks disrupt or reduce our production

Uranium 2010 Q1 updates

Operating properties

McArthur River/Key Lake

Production update

Our share of production this quarter was 3.7 million pounds U₃O₈ compared to 3.6 million pounds in the first quarter of 2009. This slight increase was mainly due to strong mill operation.

Operations update

At Key Lake, we made progress on pouring the foundations for the steam and acid plants. We expect to complete the acid, steam and oxygen plants in 2011.

The McArthur River mine performed better than planned this quarter, with strong production coming from the zone 2, panel 5 mining area. We have developed and are optimizing techniques to deal with abandoned freezepipes from the freezewall for zone 2, panels 1, 2, and 3. These techniques have been successful so far, and the related risk to 2010 production noted in our annual MD&A is no longer expected to be an issue.

The zone 4 transition is ahead of plan. We expect the freezewall will be sufficiently advanced in the second quarter to begin the development required to commence production.

We received regulatory approval this quarter to complete development of the exploration drift for zone B, which we expect to carry out over the next 2 years.

Collective bargaining with unionized employees at the McArthur River/Key Lake operations is continuing.

Rabbit Lake

Production update

Rabbit Lake produced 1.0 million pounds U₃O₈ this quarter compared to 0.5 million pounds in the first quarter of 2009. The mill operated for a longer period than in the first quarter of 2009 resulting in higher production. We expect to see large variations in mill production from quarter to quarter as we manage ore supply to ensure efficient operation of the mill.

Operations update

To support safety and reliability in the near-term and continued production in the long-term, we have begun to replace major components of the acid plant, increase the surface water handling capacity, and will continue to study future tailings expansion.

Smith Ranch-Highland and Crow Butte

Production update

Smith Ranch-Highland and Crow Butte in situ recovery (ISR) mines, located in Wyoming and Nebraska, collectively produced 0.7 million pounds U₃O₈ this quarter, compared to 0.6 million pounds in the first quarter of 2009.

Operations update

The regulators are planning public hearings for 2011 to consider our applications to expand and re-license Crow Butte. We expect production to continue throughout this licence renewal process.

Inkai

Production update

Our share of production this quarter was 0.7 million pounds U₃O₈ compared to 0.1 million pounds in the same period of 2009. Completion of the processing facilities and a stable acid supply resulted in higher production than in the first quarter of 2009.

Operations update

In mid-February, Inkai received state commissioning acceptance of the main processing plant and all approvals are now in place for the completed facility.

Inkai has submitted a potential commercial discovery notice and associated geological report for block 3 in support of an application to extend the block 3 licence for a multi-year appraisal period, to carry out:

• delineation drilling
• construction and operation of a test leach facility
• a feasibility study

In late March, we filed Inkai's first National Instrument 43-101 (NI 43-101) technical report.

Development project

Cigar Lake

As previously reported, we completed dewatering the underground development and established safe access to the underground workings in February 2010.

Work to clean up, inspect, assess and secure the underground development is progressing as planned.

In late March, we filed an updated NI 43-101 technical report for Cigar Lake.

We continue to target initial production in mid-2013.

For the rest of 2010, we will focus on carrying out our plans and implementing the strategies we have identified to move Cigar Lake towards production. Our 2010 plans include:

• completing work to secure the underground
• determining if additional remedial work is needed
• beginning to restore the underground mine systems and infrastructure to prepare for construction to resume
• drilling to upgrade mineral resources
• increasing installed pumping capacity to 2,500 m³/hr. Currently, we have 1,950 m³/hr of installed capacity
• completing the assessment of a surface freeze strategy that could potentially shorten the rampup period for the project and bring forward up to 10 million pounds of uranium production in the early years and improve project economics

Cigar Lake is a key part of our plan to double annual uranium production to 40 million pounds by 2018, and we are committed to bringing this valuable asset safely into production.

Actions have been taken, and opportunities are being pursued, to address changes that have occurred in the project and its risks — risks that are common to the development of any mining project, particularly in northern Saskatchewan's Athabasca Basin.

Projects under evaluation

Kintyre

During the first quarter we:

• completed construction of the camp to house site personnel during the evaluation stage
• started our community consultation meetings as part of our ongoing dialogue with the Martu traditional owners
• continued with the drilling necessary to confirm NI-43-101 compliant resources

Fuel services 2010 Q1 updates

Blind River Refinery

The Blind River refinery produced 2.6 million kgU of UO₃ this quarter compared to 3.6 million kgU in the first quarter of 2009. The production rate for the quarter was lower than in the first quarter of 2009, but we continue to expect total production for 2010 in the range of 11 to 13 million kgU.

Port Hope Conversion Services
Cameco Fuel Manufacturing Inc. (CFM)
Springfields Fuels Ltd. (SFL)

Fuel services production totalled 4.8 million kgU this quarter, compared to 2.1 million kgU in the first quarter of 2009. The increased production is largely due to the routine operation of the Port Hope UF₆ plant, which was not operating in the first quarter of 2009.

We issued layoff notices to 26 CFM employees in March since customer demand for fuel bundles was lower than expected. We expect the layoffs to last until at least the end of 2010.

Qualified persons

The technical and scientific information discussed in this MD&A for our material properties (McArthur River/Key Lake, Cigar Lake and Inkai) were prepared by, or under the supervision of, the following individuals who are qualified persons for the purposes of NI 43-101.

McArthur River/Key Lake

• David Bronkhorst, vice-president, Saskatchewan mining south, Cameco
• Les Yesnik, general manager, Key Lake, Cameco

Inkai

• Charles J. Foldenauer, general manager operations and development, Inkai

Cigar Lake

• Grant J.H. Goddard, vice-president, Saskatchewan mining north, Cameco

Additional information

Related party transactions

We buy significant amounts of goods and services for our Saskatchewan mining operations from northern Saskatchewan suppliers to support economic development in the region. One of these suppliers is Points Athabasca Contracting Ltd. (PACL). In the first three months of 2010, we paid PACL $3.6 million for construction and contracting services (2009 - $13.4 million). These transactions were conducted in the normal course of business. A member of Cameco's board of directors is the president of PACL.

Controls and procedures

As of March 31, 2010, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon that evaluation and as of March 31, 2010, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under applicable securities laws is recorded, processed, summarized and reported as and when required, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting during the quarter ended March 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

New accounting pronouncements

International financial reporting standards (IFRS)

The Accounting Standards Board requires Canadian publicly accountable enterprises to adopt IFRS effective January 1, 2011. Although IFRS has a conceptual framework that is similar to Canadian GAAP, there are significant differences in recognition, measurement and disclosure.

We have developed a three-phase implementation plan that will ensure compliance and a smooth transition.

Senior management and the board's audit committee are actively involved in the process. A major public accounting firm has been engaged to provide technical accounting advice and project management guidance.

Phase 1: Preliminary study and diagnostic — completed in June 2008
During this phase, we:

• completed a high-level impact assessment
• prioritized areas to evaluate in phase 2
• developed a detailed plan for convergence and implementation
• determined which information technology systems need to be modified to meet IFRS reporting requirements. We tested and implemented systems modifications by June 30, 2009.

Phase 2: Detailed component evaluation — in progress
During this phase, we are:

• assessing the impact of the adoption of IFRS on our results of operations, financial position and financial statement disclosures
• developing a detailed, systematic gap analysis of accounting and disclosure differences between Canadian GAAP and IFRS, which will help us make final decisions about accounting policies and our overall conversion strategy
• specifying all changes we need to make to existing business processes

See the detailed status below.

Phase 3: Embedding – in progress
During this final phase, we will:

• carry out the changes to our business processes
• receive the audit committee's approval of our accounting policy changes
• complete the training process for our audit committee, board members and staff
• communicate the impact of the IFRS transition to external stakeholders
• collect the financial information we need to create our 2010 and 2011 financial statements under IFRS
• receive the board's approval of the new statements

Progress update

During the quarter, we continued to evaluate key accounting policy alternatives and implementation decisions, but have not yet completed our analysis of the full accounting effects of adopting IFRS. In the second quarter of 2010, we plan to finalize our analysis of accounting policy decisions and the quantification of our January 1, 2010 opening IFRS balances. Communication of the results of that analysis will follow.

Senior management and the audit committee have approved our IFRS accounting policies, but IFRS standards are evolving and may be different at the time of transition. The International Accounting Standards Board (IASB) has several projects underway that could affect the differences between Canadian GAAP and IFRS. For example, we expect that the standards for consolidation, liabilities, discontinued operations, financial instruments, employee benefits and joint ventures could change before we adopt IFRS, and that IFRS for income taxes may change at a later date. We have been monitoring and evaluating these changes, and our analysis incorporates the standards we expect to be in effect at the time of transition.

We currently expect IFRS to affect our consolidated financial statements in the following key areas:

Asset impairment
We use a two-step approach to test for impairment under Canadian GAAP:

• We compare the carrying value of the asset with undiscounted future cash flows to see whether there is an impairment.
• If there is an impairment, we measure it by comparing the carrying value of the asset with its fair value.

International Accounting Standard (IAS) 36, Impairment of Assets, takes a one-step approach:

• Compare the carrying value of the asset with either its fair value less costs to sell or its value in use - whichever is higher.

Value in use uses discounted future cash flows, and could result in more writedowns, but the effect of this could be lower as IAS 36 allows companies to reverse impairment losses (for everything except goodwill) if an impairment is reduced due to a change in circumstances. Canadian GAAP does not allow companies to reverse impairment losses.

Employee benefits
We amortize past service costs on a straight-line basis over the expected average remaining service life of the plan participants under Canadian GAAP.

IAS 19, Employee Benefits, requires companies to expense the past service cost component of defined benefit plans on an accelerated basis. Vested past service costs must be expensed immediately. Unvested past service costs must be recognized on a straight-line basis until the benefits vest. Companies will also recognize actuarial gains and losses directly in equity rather than through profit or loss.

IFRS 1, First-Time Adoption of International Financial Reporting Standards, also allows companies to recognize all cumulative actuarial gains and losses in retained earnings at the transition date.

Share-based payments
We measure cash-settled, share-based payments to employees based on the intrinsic value of the award under Canadian GAAP. IFRS 2, Share-Based Payments, requires companies to measure payments at the award's fair value, both initially and at each reporting date.

We expect this difference to affect how we account for our phantom stock option plan.

Provisions (Including asset retirement obligations)
IAS 37, Provisions, Contingent Liabilities and Contingent Assets, requires companies to recognize a provision when:

• there is a present obligation due to a past transaction or event
• it is probable (i.e. more likely than not) that an outflow of resources will be required to settle the obligation, and
• the obligation can be reliably estimated

Canadian GAAP uses the term "likely" in its recognition criteria, which is a higher threshold than "probable", so some contingent liabilities may be recognized under IFRS that were not recognized under Canadian GAAP.

IFRS also measures provisions differently. For example:

• When there is a range of equally possible outcomes, IFRS uses the midpoint of the range as the best estimate, while Canadian GAAP uses the low end of the range.
• Under IFRS, material provisions are discounted.

Joint ventures
We proportionately account for interests in jointly controlled enterprises under Canadian GAAP. The IASB has indicated that it expects to issue a new standard in 2010 that will replace IAS 31 Interests in Joint Ventures. It is considering Exposure Draft 9, Joint Arrangements (ED 9), which proposes that an entity recognize its interest in a joint controlled enterprise using the equity method.

We expect to use the equity method to account for our joint venture interests when we transition to IFRS.

Income taxes
Under Canadian GAAP, we credit (or charge) income tax directly to equity only when it relates to items that we are crediting (or charging) directly to equity in the same period. IAS 12, Income Taxes, requires companies to credit (or charge) income tax directly to equity whether or not the related item is credited (or charged) directly to equity in the same period. That means we may have to recognize some income tax effects directly in equity rather than through net income or loss.

Under Canadian GAAP, we cannot recognize deferred tax for a temporary difference that arises from intercompany transactions. We record the taxes we pay or recover in these transactions as an asset or liability, and then recognize them as a tax expense when the asset leaves the group or is otherwise used. IAS 12 requires entities to recognize deferred taxes for temporary differences that arise from intercompany transactions, and to recognize taxes paid or recovered in these transactions in the period incurred.

The IASB may address these differences from GAAP in a fundamental review of income tax accounting at some time in the future, but this review is not likely to be soon.

First-time adoption of IFRS
IFRS 1 generally requires an entity to apply the new standards retrospectively at the end of its first IFRS reporting period, but there are some mandatory exceptions and some optional exemptions.

We are analyzing the options available to us, and currently expect to use the exemptions in the table below. This is a summary of the changes we currently believe will be most significant when we transition to IFRS – it is not a complete list of changes we will be required to make. We are still working on our analysis and have not made final decisions about the accounting policies that are available. At this stage, we have not completed our work to quantify the expected impacts of these differences on our consolidated financial statements.

Business combinations	We will have the option to apply IFRS 3, Business Combinations, retrospectively or prospectively. We plan to apply IFRS 3 prospectively to all business combinations that occurred before the transition date, except as required under IFRS 1.
Fair value as deemed cost	We will be able to choose to use the fair value of property, plant and equipment as deemed cost at the transition date, or to use the value determined under GAAP. We plan to use the historical bases under Canadian GAAP as deemed cost at the transition date.
Share-based payments	We will be able to apply IFRS 2, Share-Based Payments, to all equity instruments granted on or before November 7, 2002, and to those granted after November 7, 2002 only if they had not vested by the transition date. We plan to apply IFRS 2 to all equity instruments granted after November 7, 2002 that had not vested as of January 1, 2010, and to all liabilities arising from share-based payment transactions that existed at January 1, 2010.
Borrowing costs	We will be able to choose to apply IAS 23 retrospectively, using a date we specify, or to capitalize borrowing costs for all qualifying assets when capitalization begins on or after January 1, 2010. We plan to apply IAS 23 prospectively. For all qualifying assets, we will expense the borrowing costs we were capitalizing before January 1, 2010, and capitalize the borrowing costs that take effect on or after that date.
Employee benefits	IAS 19, Employee Benefits, requires entities to defer or amortize certain actuarial gains and losses, subject to certain provisions (corridor approach), or to immediately recognize them in equity. We plan to recognize cumulative actuarial gains and losses on benefit plans in retained earnings at the transition date.
Differences in currency translation	IAS 21, The Effects of Changes in Foreign Exchange Rates, will require us to calculate currency translation differences retrospectively, from the date we formed or acquired a subsidiary or associate. IFRS 1 gives us the option of resetting cumulative translation gains and losses to zero at the transition date. We plan to reset all cumulative translation gains and losses to zero in retained earnings at the transition date.
Decommissioning liabilities	We will have the option of applying IFRIC 1, Changes in Existing Decommissioning, Restoration and Similar Liabilities, retrospectively or prospectively. IFRIC 1 will require us to add or deduct a change in our obligations to dismantle, remove and restore items of property, plant and equipment, from the cost of the asset it relates to. The adjusted amount is then depreciated prospectively over the asset's remaining useful life. We plan to adopt IFRIC 1 prospectively at the transition date.

As we proceed with our transition, we are also assessing the impact on our internal controls over financial reporting, and on our disclosure controls and procedures. Changes in accounting policies or business processes could require the implementation of additional controls or procedures to ensure the integrity of our financial disclosures. We plan to design and test the effectiveness of new controls in 2010.

We conducted several educational and training sessions for our audit committee and the board of directors in 2009. During these sessions, management and external advisors provided the board with detailed background information on IFRS accounting standards (including IFRS 1 elections), the implications of policy choices on our financial reporting, and a preliminary view of the expected format and content of our financial statements and notes upon transition. Management gives the audit committee quarterly project status updates and presentations.

We began training management and accounting staff in 2008. Training is being delivered mainly by external advisors, and focusing on the accounting issues most relevant to Cameco. Sessions will continue throughout 2010.

Our transition plan includes the need to inform key external stakeholders about the anticipated impact of the IFRS transition on our financial reporting. In 2009, we provided an information update as part of our investor day presentations. We are planning further communications with the investment community in the latter half of 2010.

We are also evaluating the impact of IFRS on our business activities in general. At this stage, we do not believe the adoption of IFRS will have a material effect on our risk management practices, hedging activities, capital requirements, compensation arrangements, compliance with debt covenants or other contractual commitments.