Cameco Corporation Management’s Discussion and … · Cameco Corporation Management’s...

Cameco Corporation Management’s Discussion and Analysis (MD&A)

For the period ended September 30, 2009

The following discussion of the financial condition and operating results of Cameco Corporation has been prepared as of October 30, 2009 and updates our first quarter, second quarter and annual MD&A, and should be read in conjunction with the unaudited consolidated financial statements and notes for the period ended September 30, 2009, as well as the audited consolidated financial statements for the company for the year ended December 31, 2008 and MD&A of the audited financial statements, both of which are included in the 2008 annual financial review. No update is provided where an item is not material or where there has been no material change from the discussion contained in our first quarter, second quarter and annual MD&A. The financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The 2008 annual financial review is available on the company’s website at cameco.com, on sedar.com and on EDGAR at sec.gov/edgar.shtml. Statements contained in this MD&A, which are not historical facts or a description of present circumstances, are forward-looking statements that involve risks, uncertainties and other factors that could cause actual results to differ materially from those expressed or implied by such forward-looking statements. For more detail on these factors, see the section titled “Caution Regarding Forward-Looking Information” in this MD&A, the section titled “Risks and Risk Management” in the MD&A contained in the company’s 2008 annual financial review, and the section titled “Risk Factors” in the company’s 2008 annual information form.

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Note: All dollar amounts are expressed in Canadian dollars unless otherwise stated. Three months

ended September 30Nine months

ended September 30 Financial Highlights 2009 2008 2009 2008

Change %1

Revenue ($ millions) 694 729 2,083 1,941 7 Earnings from operations ($ millions) 224 176 585 459 27 Cash provided by operations2

($ millions) 248 109 565 368 54

Net earnings ($ millions) 172 135 501 419 20 Adjusted net earnings ($ millions)3 104 127 334 414 (19) Earnings per share (EPS) – basic ($) 0.44 0.39 1.30 1.22 7 EPS – diluted ($) 0.44 0.39 1.29 1.21 7 EPS – adjusted and diluted ($)3 0.26 0.37 0.86 1.19 (28) Weighted average common shares outstanding (millions) 393 346 386 345 12

Average uranium (U3O8) spot price ($US/lb U3O8)

45.29 60.50 46.10 65.11 (29)

Average realized uranium price • $US/lb U3O8 • $Cdn/lb U3O8

34.24 39.18

37.88 39.90

37.26 45.80

42.69 44.42

(13)

3 Average realized electricity price ($/MWh) 66 59 64 57 18

Average Ontario electricity spot price per megawatt hour ($/MWh) 22 51 29 49 (41)

FINANCIAL RESULTS Consolidated Earnings Third Quarter For the three months ended September 30, 2009, our net earnings were $172 million ($0.44 per share diluted), $37 million higher than net earnings of $135 million ($0.39 per share diluted) recorded in the third quarter of 2008. For the three months ended September 30, 2009, our adjusted net earnings3 were $104 million ($0.26 per share adjusted and diluted), $23 million lower than adjusted net earnings of $127 million ($0.37 per share adjusted and diluted) recorded in the third quarter of 2008. The decrease was due to lower earnings in the uranium and gold businesses. Gross profit from our uranium

1 Represents the change for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. 2 Including changes in working capital. For more information on working capital changes, refer to note 13 of the third quarter

unaudited consolidated financial statements. 3 Net earnings for the quarters and nine months ended September 30, 2008 and 2009 have been adjusted to exclude a number of

items. Adjusted net earnings is a non-GAAP measure. For a description see “Use of Non-GAAP Financial Measures” on page 28.

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business was impacted primarily by lower sales volumes and a higher unit cost of product and services sold in the quarter. See the section titled “Uranium Results – Third Quarter” in this document for more information. The gold business was impacted by lower gold production and higher operating costs. Compared to the third quarter of 2008, exploration expenditures were $4 million lower, at $18 million, with uranium exploration expenditures decreasing by $5 million to $11 million. Gold exploration expenditures at Centerra Gold Inc. (Centerra) were up $1 million at $7 million compared to $6 million in the third quarter of 2008. In the third quarter of 2009, our income tax expense, based on adjusted net earnings, was a $7 million recovery compared to a $3 million recovery in the same period of 2008. Our effective income tax rate was -6% in the third quarter of 2009 compared to -2% in 2008. During the third quarter of 2009, we obtained reasonable assurance that certain qualifying expenditures under investment tax credit programs would ultimately be realized and accordingly, we began to recognize the expected benefits in our financial results. As a result, we have recorded a net recovery of $9 million in the quarter, consisting of recoveries related to exploration expenditures ($5 million), research and development costs ($4 million) and Cigar Lake remediation ($3 million), partially offset by a $3 million increase in income tax expense. In the third quarter of 2009, direct administration costs were $40 million, a decrease of $5 million compared to 2008 due mainly to reduced requirements for system technology enhancements and lower recruiting activity. In the third quarter of 2009, stock-based compensation costs were $2 million compared to a recovery of $77 million in the third quarter of 2008. Late in 2008, we amended our stock option program and began accounting for our options using their fair value at the grant date. Under this method, our stock option expense is highly predictable. For this reason, we will not be adjusting our net earnings for stock option expense in 2009.

Three months ended September 30 Administration ($ millions)

2009 2008 Direct administration 40 45 Stock-based compensation expense (recovery)1 2 (77) Total administration 42 (32)

1 Stock-based compensation includes amounts charged to administration under the stock option, deferred share unit, performance share unit and phantom stock option plans.

Nine Months Ended September 30, 2009 For the nine months ended September 30, 2009, our net earnings were $501 million ($1.29 per share diluted), $82 million higher than net earnings of $419 million ($1.21 per share diluted) recorded in the first nine months of 2008.

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For the nine months ended September 30, 2009, our adjusted net earnings4 were $334 million ($0.86 per share adjusted and diluted), $80 million lower than adjusted net earnings of $414 million ($1.19 per share adjusted and diluted) recorded for the same period in 2008. The decrease was due to lower earnings in the gold and uranium businesses, partially offset by higher results in the fuel services and electricity businesses. Increased costs adversely affected uranium profits. See the section titled “Uranium Results – Nine Months Ended September 30, 2009” in this document for more information. The gold business was impacted by lower gold production and higher operating costs. Gross profit from our electricity business benefited from increased generation and an increase in the realized price, while realized selling prices for fuel services were higher in the first nine months of 2009. Compared to the first nine months of 2008, exploration expenditures were $1 million lower, at $53 million, with uranium exploration expenditures decreasing by $5 million to $33 million. Gold exploration expenditures at Centerra were $4 million higher at $19 million compared to the first nine months of 2008. In the first nine months of 2009, our income tax expense, based on adjusted net earnings, was a $1 million recovery compared to $21 million expense in the same period of 2008. Our effective income tax rate was 0% in the first nine months of 2009 compared to 5% in 2008. In the first nine months of 2009, direct administration costs were $108 million, a decrease of $6 million compared to 2008 due mainly to reduced requirements for system technology enhancements and lower recruiting activity. The rate of growth in the workforce has slowed since the third quarter of 2008. In the first nine months of 2009, stock-based compensation costs were $12 million compared to a recovery of $53 million in 2008. As noted previously, we will not be adjusting our net earnings for stock option expense in 2009.

Nine months ended September 30 Administration ($ millions)

2009 2008 Direct administration 108 114 Stock-based compensation expense (recovery)1 12 (53) Total administration 120 61

1 Stock-based compensation includes amounts charged to administration under the stock option, deferred share unit, performance share unit and phantom stock option plans.

4 Net earnings for the quarters and nine months ended September 30, 2008 and 2009 have been adjusted to exclude a number of

items. Adjusted net earnings is a non-GAAP measure. For a description see “Use of Non-GAAP Financial Measures” on page 28.

Quarterly Financial Results ($ millions except per share amounts)

2009 2008 2007 Highlights

Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4

Revenue 694 774 615 918 729 620 593 494

Net earnings 172 247 82 31 135 150 134 61 EPS – basic ($) 0.44 0.63 0.23 0.08 0.39 0.44 0.38 0.18

EPS – diluted ($) 0.44 0.63 0.22 0.08 0.39 0.42 0.37 0.17

Cash from operations1 248 125 191 340 109 113 146 57

1 Including changes in working capital. For more information on working capital changes, refer to note 13 of the third quarter unaudited consolidated financial statements.

Revenue of $694 million in the third quarter of 2009 was 10% lower than in the second quarter due to decreased sales volumes and realized selling prices (in Canadian dollars) in the uranium business. Revenues from the fuel services, electricity and gold businesses were comparable to that of the second quarter of 2009. Net earnings in the third quarter of 2009 were significantly lower than in the second quarter of 2009 due largely to the lower sales volumes and prices in the uranium business. The average realized uranium price in the third quarter was the lowest for the year due to the mix of contract deliveries during the quarter. Profits from the fuel services business were lower due to decreases in realized selling prices (in Canadian dollars). Our financial results tend to fluctuate largely due to the timing of deliveries and product purchases in the uranium and fuel services businesses. Cash Flow In the third quarter of 2009, we generated $248 million in cash from operations compared to $109 million in the same period of 2008. The increase of $139 million was related to lower working capital requirements partially offset by lower sales in the uranium business. In the first nine months of 2009, we generated $565 million in cash from operations compared to $368 million in the same period of 2008. The increase of $197 million was related to higher sales and a decrease in working capital requirements compared to the prior year. The change in working capital is primarily related to lower accounts receivable in 2009 compared to 2008.

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Balance Sheet At September 30, 2009, our total debt was $1,172 million, representing a decrease of $141 million compared to December 31, 2008. During the quarter, we filed a shelf prospectus in Canada for offerings of up to $1 billion in senior debt. Subsequently, we issued $500 million in unsecured, 10-year debentures at an interest rate of 5.67%. We intend to use the net proceeds of this issue to refinance existing indebtedness (which includes repayment of commercial paper as it matures - $126 million outstanding at September 30, 2009) and for general corporate purposes. Also included in our September 30, 2009 total debt was $173 million, which represents our proportionate share of BPLP’s capital lease obligation. At September 30, 2009, our consolidated net debt to capitalization ratio was 10%, down from 23% at the end of 2008. The decrease was due largely to the issue of equity in the first quarter of 2009 when we issued 26.7 million common shares for net proceeds of approximately $440 million. Our product inventories increased by $19 million compared to the end of 2008 due to increased inventories of conversion services products and higher average carrying values for uranium. At September 30, 2009, our consolidated cash balance totalled $670 million, with cash held by Centerra accounting for $175 million of this amount. Foreign Exchange Update During the quarter, the Canadian dollar strengthened against the US dollar from $1.00 (US) for $1.16 (Cdn) at June 30, 2009 to $1.00 (US) for $1.07 (Cdn) at September 30, 2009. At September 30, 2009, we had foreign currency contracts of $1,490 million (US) and EUR 36 million. The US currency contracts had an average rate of $1.00 (US) for $1.13 (Cdn) at September 30, 2009, which reflects the original foreign exchange spot prices at the time the contracts were entered into and includes net deferred gains. At September 30, 2009, the net mark-to-market gain on all foreign exchange contracts was $87 million compared to a $2 million gain at June 30, 2009. Timing differences between the maturity dates and designation dates on previously closed hedge contracts may result in deferred revenue or deferred charges. At September 30, 2009, net deferred gains totalled $46 million. The schedule for net deferred gains to be released to earnings, by year, is as follows:

Deferred Gains (Charges) 2009 2010 2011

$ millions (Cdn) 7 34 5

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OUTLOOK Below is a table summarizing our 2009 consolidated outlook as well as the outlook for each of our business segments. Updates from the outlook contained in the table disclosed in our second quarter MD&A were made to the following items (in bold): fuel services production, nuclear electricity revenue, gold production, and gold capital expenditures. 2009 Financial Outlook1

2009 Outlook Consolidated Uranium Fuel Services Nuclear Electricity Gold

Revenue Increase 5% to

10%2 Increase 5% to

10%3 Increase 5% to

10% Increase 15%

to 20%4 -

Administration costs

Decrease 5% to 10% - - - -

Tax rate Less than 5% - - - -

Sales volume - 34 to 36 million lbs

Decline slightly - -

Unit cost of product sold - Increase 20%

to 25%5 - Decrease slightly -

Capacity factor - - - About 90% -

Production - 20 million lbs 11 to 13 million kgU6 - 620,000 to

630,000 oz7 Capital expenditures $367 million8 - - $38 million $88 million

(US) 9

1 We only provide outlook for the select items shown in the table. For all other items listed in the table, no outlook is provided. 2 This is the revenue outlook for the uranium, fuel services and nuclear electricity businesses and does not include gold. 3 Based on a uranium spot price of $49.50 (US) per pound, reflecting the UxC spot price as of October 26, 2009. 4 Outlook contained in the second quarter MD&A table – revenue expected to increase 10% to 15% over 2008. 5 The unit cost of product sold, excluding purchases, is expected to rise by 5% to 10%. The remainder of the year-over-year

increase is attributable to the cost of purchased material. 6 Outlook contained in the second quarter MD&A table – production expected to total between 8 and 12 million kgU in 2009. 7 Outlook contained in the second quarter MD&A table – production to be 680,000 to 730,000 ounces. 8 Our consolidated outlook for capital expenditures does not include Bruce Power or Centerra capital expenditures. 9 Outlook contained in the second quarter MD&A table – capital expenditures to be $107 million (US). Material changes, from those contained in our annual MD&A, as updated by the information contained in our first and second quarter MD&A, have been made to the 2009 outlook for nuclear electricity revenue, fuel services production and gold production. These changes are discussed below. In addition, we are including our 2009 outlook for uranium unit cost of product and services sold (which is unchanged from the previous quarter), uranium production outlook for 2009 to 2013, updated expected realized uranium price sensitivity table for 2009 to 2013 and an analysis of the sensitivity of our results to changes in the US to Canadian dollar and the spot prices for uranium, electricity and gold.

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2009 Outlook for Uranium We continue to expect our unit cost of product and services sold to rise by 20% to 25% compared to 2008. The unit cost of product and services sold represents the average cost of inventory, which includes both produced and purchased material. Consistent with prior disclosure, the estimated cost of produced material is expected to contribute a 5% to 10% increase in our unit cost of product and services sold. The remainder of the year-over-year increase is attributable to the cost of purchased material. We purchase uranium to support our sales activities, including higher trading volumes. The supply interruption provisions in our sales contracts protect us from having to purchase uranium in the event of a shortfall in planned production or deliveries under the highly enriched uranium agreement. Uranium Production Outlook (2009 to 2013) We are providing an update for our near-term production outlook in the table below.

Cameco’s Share of Production (million pounds U3O8)1

Current Forecast 2009 2010 2011 2012 2013 McArthur River/Key Lake 13.1 13.1 13.1 13.1 13.1 Rabbit Lake 3.6 3.6 3.6 2.8 1.7 US ISR 2.6 2.5 2.6 3.0 3.4 Inkai2 0.9 2.3 3.1 3.1 3.1 Total* 20.2 21.5 22.4 22.0 21.3

* While a single estimate has been included for each year of the production outlook, actual production may differ significantly from these estimates as forecasting production is inherently uncertain.

1 A revised production forecast for Cigar Lake will be provided after the mine has been dewatered, the condition of the underground development has been assessed, and the findings incorporated in the new mine development and production plans.

2 Inkai mineral reserves assume production at an annual rate of 5.2 million pounds of U3O8 (our share 60%). Inkai currently has regulatory approval to produce at an annual rate of 2.6 million pounds (100% basis) and an application for regulatory approval to increase annual production to 5.2 million pounds (100% basis) was made in 2005.

The current uranium production forecast noted above for the company is forward-looking information. This forward-looking information is based upon the key assumptions and subject to the material risks that could cause results to differ materially, and which are discussed under the heading “Caution Regarding Forward-Looking Information and Statements”. In particular, we have assumed that the company’s schedule for the development and rampup of production from Inkai is achieved (which requires, among other things, resolution of the issues surrounding acid availability); the successful transition to new mining areas at McArthur River; that the company is able to obtain or maintain the necessary permits and approvals from government authorities to achieve the forecast production; and that there is no disruption in production due to natural phenomena, labour disputes, political risks or other development and operation risks. Material risks that could cause actual results to differ materially include our inability to achieve forecast production levels for each operation; our development and rampup of production from Inkai does not proceed as anticipated; the transition to new mining areas at McArthur River is not successful; the inability to obtain or maintain necessary permits or government approvals; and a disruption or reduction in production. No assurance can be given that the indicated quantities will be produced. Expected future production estimates are inherently uncertain, particularly in the later years of the forecast, and could materially change over time.

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Uranium Price Sensitivity (2009 to 2013) The prices shown in our expected realized uranium price sensitivity table are intended to provide the reader with a general indication of how our expected realized prices for uranium may vary with changes in market prices over the period 2009 to 2013. The expected realized prices reported in this table may change from quarter to quarter based on changes in a number of variables, including: • new contracts entered into during the quarter, • variations in the actual spot price or long-term price during the most recent quarter from the

price assumptions in the table published in the previous quarter, • changes in inflation assumptions, • changes in delivery plans from those assumed in the table published in the previous quarter

as a result of requirements contracts or volume flexibility terms contained in some contracts, and

• changes in the volume of uncommitted material. Due to the number of variables affecting our realized prices, we have made a simplifying assumption by setting the spot price at the levels noted, and calculating our expected realized prices accordingly. For example, under the $60.00 (US) spot price scenario, the calculation of realized prices assumes the spot price reaches $60.00 (US) at September 30, 2009, and remains at that level through 2013. Each column in the table should be read assuming the column header spot price remains constant for the entire five-year period. Many of the contracts we are delivering into during the period 2009 to 2013 were finalized in 2003 to 2005 when industry market prices were in the range of about $11 to $31 (US) (see the table below for industry average uranium market prices from 2003 to 2008). To the extent these contracts have pricing fixed at these historic uranium prices or have low ceiling prices, they will yield lower prices than current market prices. As these older contracts expire over the next few years and we begin delivering into more contracts signed since 2006, our average realized price will benefit. The table below outlines the industry average uranium market prices over the past few years which may help put our average realized prices into perspective.

Industry Average Uranium Market Prices ($US/lb U3O8) 2003 2004 2005 2006 2007 2008 Spot price indicator 11.55 18.60 28.67 49.60 99.29 61.58 Long-term price indicator 12.10 21.00 30.66 49.90 90.83 82.50

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The uranium price sensitivity table for the period 2009 to 2013 below has been updated to reflect deliveries made and contracts entered into up to September 30, 2009.

Expected Realized Uranium Price Sensitivity Under Various Spot Price Assumptions (Rounded to the nearest $1)

Current $US/lb U3O8 Spot Price $20 $40 $60 $80 $100 $120 $140

2009 37 38 39 40 41 43 44

2010 33 38 47 53 60 68 75

2011 33 38 48 55 63 72 80

2012 37 40 49 58 67 76 85

2013 43 46 56 66 76 87 96

This price table is forward-looking information and is based upon the material assumptions, and subject to the material risks, discussed under the heading “Caution Regarding Forward-Looking Information and Statements”, as well as the following key assumptions and material risks which could cause actual prices to vary:

• sales volume of approximately 36 million pounds for 2009 (which has been adjusted for the accounting requirements of the product loan agreement) and a sales volume of about 30 million pounds for each year thereafter. Variations in our actual sales volume could lead to materially different results,

• utilities take the maximum quantities allowed under their contracts, unless a delivery notice stating they will take lower quantities has already been provided, which is subject to the risk that they take lower quantities than expected for a period or defer quantities resulting in materially different realized prices for that period,

• we defer a portion of deliveries under contract for 2010 and 2011 as a result of exercising our rights under supply interruption/supply reduction provisions,

• all volumes for which there are no existing sales commitments are assumed to be delivered at the spot price assumed for each scenario, which is subject to the risk that sales are at prices other than spot prices which could result in materially different realized prices,

• the average long-term price indicator in a given year is assumed to be equal to the average spot price for that entire year. Fluctuations in the spot price or the long-term price during the course of a year could lead to materially different results as our market-related contracts may reference the spot or long-term price indicator at the time of delivery, and

• an inflation rate of 2.0%, but variations in the inflation rate could have a material impact on actual results.

The assumptions stated above, including our annual sales volumes and the price realized from them, are made solely for the purpose of the foregoing price table and do not necessarily reflect our views of anticipated results. Fuel Services Outlook for 2009 In 2009, fuel services production at Port Hope and SFL is now expected to total between 11 and 13 million kgU compared to our previous estimate of between 8 and 12 million kgU. The increase in our estimate is related to the increased production expected at the Port Hope UF6 plant as a result of increased confidence in the supply of hydrofluoric acid (HF). HF is a primary feed material for the production of UF6. Production had been suspended due to the lack of availability of HF on acceptable terms from December 2008 to mid June 2009. However, we have broadened our sources of supply and are receiving adequate HF. BPLP’s Outlook for 2009 Electricity revenue in 2009 is expected to increase 15% to 20% over 2008 compared to the 10% to 15% increase previously reported. This change in outlook is largely the result of a continued deterioration in the Ontario electricity market in the third quarter and BPLP recognizing revenue under its agreement with OPA.

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In addition, BPLP has in place financial contracts that correspond to about 45% of planned generation over the remainder of the year. Revenue recognized under the agreement with the OPA plus benefits under the financial contracts will contribute to higher realized electricity revenue for 2009. Gold Outlook for 2009 Centerra expects its 2009 gold production to total between 620,000 and 630,000 ounces compared to its second quarter estimate of 680,000 to 730,000 ounces. The reduction is due to lower than expected production at Kumtor resulting from deferred access to the high grade component of the SB zone in the central pit to the fourth quarter of 2009. Gold production at Kumtor is expected by Centerra to be approximately 500,000 ounces compared to the second quarter estimate of 560,000 to 600,000 ounces. Foreign Exchange Sensitivity At September 30, 2009, every one-cent increase/decrease in the value of the Canadian dollar versus the US dollar for the remainder of the year would result in a corresponding increase/decrease in net earnings for the balance of the year of about $11 million (Cdn). This sensitivity is based on an expected effective exchange rate of $1.00 (US) being equivalent to about $1.06 (Cdn), which was the rate on October 26, 2009. Uranium Price Sensitivity (2009) For the remainder of 2009, a $5.00 (US) per pound change in the uranium spot price from $49.50 (US) per pound (reflecting the UxC spot price at October 26, 2009) would change revenue by $7 million (Cdn) and net earnings by $5 million (Cdn). This sensitivity is based on an expected effective exchange rate of $1.00 (US) being equivalent to about $1.06 (Cdn), which was the rate on October 26, 2009. Electricity Price Sensitivity Analysis At September 30, 2009, BPLP had about 3.1 TWh under contract for the balance of 2009, which is equivalent to about 45% of Bruce B generation at its planned capacity factor. Based on the assumption that for the remainder of 2009 the spot price will remain below the floor price provided for under the agreement with the OPA, a $1 change in the electricity spot price from its current level will change our earnings by less than $1 million. Gold Price Sensitivity Analysis For the remainder of 2009, a $25.00 (US) per ounce change in the gold spot price would change our net earnings by about $3 million (Cdn). This sensitivity is based on an expected effective exchange rate of $1.00 (US) being equivalent to about $1.06 (Cdn), which was the rate on October 26, 2009. The foregoing update to the outlook for the year 2009 contained in our annual MD&A for the year ended 2008, as updated by the information contained in our first and second quarter MD&A for 2009, is forward-looking information and, except as stated in the footnotes above, is based upon the same key assumptions and subject to the same material risk factors that could cause results to differ materially which were discussed under the heading "Caution Regarding Forward-looking Information and Statements” in our annual MD&A. These include assumptions regarding production levels, purchases, sales volumes, costs and market prices, and the risk of variations in them; the risk of material adverse changes in foreign currency exchange rates and interest rates, and the assumption that they will remain constant or improve in our favour; the risk of unexpected or challenging geological, hydrological or mining conditions which deviate significantly from our assumptions regarding those conditions; political risks and the risk of adverse changes in government legislation, regulations and policies, which we have assumed will not occur; and the success and timely completion of planned development and remediation projects, and the risks associated with those projects.

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BUSINESS SEGMENT RESULTS Our results come from four business segments: • Uranium • Fuel services • Nuclear electricity generation • Gold URANIUM Highlights

Three months ended September 30

Nine months ended September 30

2009 2008 2009 2008 Revenue ($ millions)1 329 396 1,108 1,062 Gross profit ($ millions) 69 120 356 473 Gross profit % 21 30 32 44 Average realized price ($US/lb) ($Cdn/lb)

34.24 39.18

37.88 39.90

37.26 45.80

42.69 44.42

Sales volume (million lbs)1 8.3 9.8 23.9 23.6 Production volume (million lbs) 5.6 2.8 14.1 11.8

1 Revenue in the amount of $85 million on 2.6 million pounds previously deferred due to a standby product loan was recognized in the first quarter of 2008 as a result of the cancellation of a product loan agreement.

Uranium Results Third Quarter Compared to the third quarter of 2008, revenue from our uranium business was lower by $67 million at $329 million due to a 15% decrease in reported sales volumes and a 2% decrease in the realized selling price (in Canadian dollars). The timing of deliveries of uranium products within a calendar year is at the discretion of customers. Therefore, our quarterly delivery patterns can vary significantly. The decrease in the average realized price was related to lower realized prices under market-related and fixed-price contracts. A more favourable foreign exchange rate partially mitigated the Canadian dollar decline. Our total cost of products and services sold, including depreciation, depletion and reclamation (DD&R), decreased to $260 million in the third quarter of 2009 from $275 million in the third quarter of 2008 due to the 15% decrease in sales volume, partially offset by a 12% increase in the unit cost of product and services sold. The unit cost of product and services sold for the third quarter continued to be negatively impacted by recent purchases at near market prices. Nine Months Ended September 30, 2009 Compared to the first nine months of 2008, revenue from our uranium business increased by $46 million to $1,108 million due to a 3% increase in the realized selling price (in Canadian dollars) and a 1% increase in reported sales volumes. The timing of deliveries of uranium products within a calendar year is at the discretion of customers. Therefore, our quarterly delivery patterns can

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vary significantly. The increase in the average realized price (in Canadian dollars) was related to higher prices under fixed-price contracts and a more favourable foreign exchange rate, partially offset by lower realized prices under market-related contracts. Our total cost of products and services sold, including DD&R, increased to $752 million in the first nine months of 2009 from $589 million in 2008 due primarily to a 26% increase in the unit cost of product and services sold. The unit cost of product and services sold was negatively impacted by the carryover effect of lower production in 2008, recent purchases at near market prices, higher royalties and increased input costs. Uranium Market Update On July 28, 2009, the US Department of Energy (DOE) announced an expanded and accelerated cleanup effort at its Portsmouth gaseous diffusion plant in Piketon, Ohio. The expanded cleanup will cost between $150 million to $200 million (US) per year over the next four years and is proposed to be funded by providing the cleanup contractor with excess uranium from DOE's stocks. The quantity of uranium transferred by the DOE to fund the work would be determined using spot market indices at the time of transfer. The proposed use of uranium inventories is in conflict with DOE’s “Excess Uranium Inventory Management Plan” adopted in 2008. The US uranium industry is lobbying DOE and the US government to reconsider its proposal and is considering legal action to protect its interests. The threat of additional DOE material reaching the market in the near term contributed to the decline of the uranium spot price during the third quarter. The UxC spot price fell from $47.00 (US) per pound at the time of DOE's announcement to $42.75 (US) per pound at the end of the quarter. Uranium Spot Market Outlined below are the industry average spot market prices (TradeTech and UxC) as at the dates specified.

Sept. 30/09 June 30/09 Sept. 30/08 June 30/08 Average spot market price ($US/lb U3O8)

$42.88 $51.50 $52.50 $59.00

In the spot market, where purchases call for delivery within one year, the volume reported for the third quarter of 2009 was about 10 million pounds U3O8. For the nine months of 2009, the volume was about 40 million pounds. This compares to about 14 million pounds in the third quarter of 2008 and about 31 million pounds in the first nine months of 2008. The UxC spot U3O8 price started the third quarter at $52.00 (US) per pound and continued to decline during the quarter, reaching $42.00 (US) per pound on September 21, 2009. The spot price ended the quarter at $42.75 (US) per pound. Since then the UxC spot U3O8 price has increased and is currently at $49.50 (US) per pound as at October 26, 2009.

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Uranium Long-Term Market Outlined below are the industry average long-term market price indicators (TradeTech and UxC) as at the dates specified.

Sept. 30/09 June 30/09 Sept. 30/08 June 30/08

Average long-term market price ($US/lb U3O8)

$64.50 $65.00 $75.00 $82.50

Long-term contracts usually provide for deliveries to begin more than two years after contracts are finalized and use a number of pricing formulas including fixed prices adjusted by inflation indices and market referenced prices (spot and long-term indicators). Uranium Operations Update Uranium Production



Cameco’s share of production (million lbs U3O8) 2009 2008 2009 2008

2009 planned production1

McArthur River/Key Lake 3.8 2.1 9.3 8.5 13.1

Rabbit Lake 0.9 0.2 2.4 1.7 3.6 Smith Ranch/Highland 0.4 0.3 1.3 1.0 1.8 Crow Butte 0.2 0.1 0.6 0.4 0.8 Inkai 0.3 0.1 0.5 0.2 0.9 Total 5.6 2.8 14.1 11.8 20.2

1 See the section titled “Uranium Production Outlook (2009 to 2013)” in this document for more information about the assumptions and risk factors associated with this production forecast.

McArthur River/Key Lake Our share of production of U3O8 at McArthur River/Key Lake during the third quarter was 3.8 million pounds compared to 2.1 million pounds produced in the same period of 2008. Production varies from quarter to quarter depending on the timing of mill shutdowns. The mill is operating well and no further shutdowns are planned this year. Our share of production at the end of the third quarter of 2009 was 9.3 million pounds U3O8 compared to 8.5 million pounds over the same period in 2008. We continue to expect our share of production to be 13.1 million pounds in 2009. At McArthur River, the initial raisebore chamber tunnel for zone 2, panel 5 was completed within the protection of freezewalls. This marks the first time development has been accomplished through the unconformity into the Athabasca sandstone. Production from this chamber is expected to start in the fourth quarter. Zone 2, panel 5 is planned to account for approximately two-thirds of McArthur River mine production in 2010. We expect approximately 85 million pounds U3O8 to be mined from this area. Portions of the new production raises will intersect the original freezewall developed for mining in zone 2, panels 1, 2 and 3. The original

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freezewall is redundant now that the freezewall for zone 2, panel 5 is in place. The steel freezepipes contained in the original freezewall pose a mining challenge. We have developed a method to remove the pipes in advance of production and are progressing with this work. Timely removal of the steel freezepipes now represents the largest remaining schedule risk that could impact 2010 production rates in this area. Over the past year, we have successfully addressed the risks associated with freeze drilling, ground freezing and development of the first raisebore chamber for this new production area. In lower zone 4, freezehole drilling is progressing well and is on track to be completed by year end. Freezing of this new ore source is expected to begin in the first quarter of 2010 with initial production planned in the latter part of 2010. Rabbit Lake Rabbit Lake produced 0.9 million pounds U3O8 in the third quarter of 2009 compared to 0.2 million pounds in the third quarter of 2008. The planned summer shutdown of the mill was carried out over June and July this year, resulting in greater mill operating time in the third quarter of 2009 compared to the third quarter of 2008. For the first nine months of 2009, Rabbit Lake produced 2.4 million pounds U3O8, compared to 1.7 million pounds for the nine months ending September 30, 2008. During the third quarter, commissioning of the circuit to reduce molybdenum and selenium in the mill effluent continued. The circuit is expected to begin operation in the fourth quarter of 2009. Commissioning of a new tailings pipeline for the expanded Rabbit Lake in-pit tailings management facility was completed and placement of tails commenced during the quarter. Smith Ranch-Highland and Crow Butte Smith Ranch-Highland and Crow Butte in situ recovery (ISR) mines, located in Wyoming and Nebraska, produced 0.6 million pounds U3O8 in the third quarter 2009, an increase from 0.4 million pounds in the third quarter of 2008. For the first nine months of 2009, these operations produced 1.9 million pounds U3O8, an increase from 1.4 million pounds produced during the same period in 2008. Cigar Lake We continue to make progress in remediating the inflow that occurred August 12, 2008 during the dewatering of the underground workings. On October 23, 2009, we announced that dewatering of the underground development at Cigar Lake had resumed. Dewatering is progressing as planned. We will provide new estimates of the planned production date and capital cost after the mine has been dewatered, the condition of the underground has been evaluated and the mine plan has been updated to reflect any resulting information.

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Inkai During the third quarter of 2009, our share of uranium production from blocks 1 and 2 was about 0.3 million pounds U3O8. Our share of production for the first three quarters of 2009 was 0.5 million pounds U3O8 compared to 0.2 million pounds in the same period in 2008. All of the circuits of the main processing plant have been commissioned and are undergoing optimization. A new tax code became law on January 1, 2009. Inkai and the Kazakh government have signed an amendment to Inkai’s Resource Use Contract to adopt the new tax code. We do not expect the new tax code will have a material impact on Inkai at this time. However, the elimination of tax stabilization under the new tax code could be material to Inkai in the future. Uranium Exploration Update Saskatchewan Exploration During the third quarter, diamond drilling programs were completed on six projects with more than 14,500 metres completed. Active projects included Cree Extension, Dawn Lake, McArthur River, Moon Lake, Read Lake and Virgin River. At McArthur River exploration drilling focused on areas southwest and northeast of the mine. Significant mineralization was encountered on the Moon Lake project in two holes drilled 50 metres apart at depths of 550 metres. This new mineralization is located in basement rock, approximately two kilometres south and on trend with the Millennium deposit. Further drilling on the Centennial deposit, Virgin River project, has added additional mineralized intercepts. Canadian Exploration Diamond drilling programs were completed on the Aberdeen and Turqavik projects in Nunavut and on the Otish project in Quebec. Several holes displayed encouraging results and will require follow-up. Global Exploration Australia The initial drill program to confirm the historical resources at Angela was completed in September. Environmental studies are on-going. Diamond drilling at Kintyre has begun and will continue into 2010 to delineate the Kintyre deposits and facilitate a feasibility study. Drilling in Arnhem Land on the Wellington Range project during the third quarter encountered significant uranium mineralization in a sandstone column within a fault zone. We will be focusing on this target in future programs. Kazakhstan A drilling program is ongoing at Inkai, block 3 to support a commercial discovery application that is expected to be filed before the exploration licence expires in July 2010.

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FUEL SERVICES Highlights



2009 2008 2009 2008 Revenue ($ millions) 50 69 186 182 Gross profit ($ millions) 4 (3) 36 (6) Gross profit % 7 (5) 20 (3) Sales volume (million kgU)1 2.8 3.7 8.9 10.2 Production volume (million kgU)2 4.1 1.8 8.4 5.7

1 Kilograms of uranium (kgU). 2 Production volume includes UF6, UO2, fuel fabrication, and UF6 supply from Springfields Fuels Ltd. (SFL). Fuel Services Results Third Quarter In the third quarter of 2009, revenue from our fuel services business was $50 million, $19 million lower compared to the same period in 2008 due to a 24% decrease in reported sales volumes and a 3% decline in the average realized price (in Canadian dollars) for fuel services products. The timing of deliveries of fuel services within a calendar year is at the discretion of customers. Therefore, our quarterly delivery patterns can vary significantly. Total cost of products and services sold, including DD&R, decreased to $46 million in the third quarter from $72 million for the same period in 2008. The cost of products sold in 2008 was impacted by the curtailment of production from the Port Hope UF6 conversion plant. In the third quarter of 2008, the plant was shutdown to allow for the cleanup of contaminated soil and all operating costs associated with the UF6 conversion plant were expensed as incurred ($15 million). In 2009, the plant was operational throughout the third quarter and operating costs were allocated to inventory. Nine Months Ended September 30, 2009 In the first nine months of 2009, revenue from our fuel services business was $186 million, an increase of $4 million compared to the same period in 2008 due to an 18% increase in the average realized price for fuel services products, primarily UF6 conversion, partially offset by a 13% decline in sales volumes. The timing of deliveries of fuel services within a calendar year is at the discretion of customers. Therefore, our quarterly delivery patterns can vary significantly. Total cost of products and services sold, including DD&R, decreased to $149 million in the first nine months of 2009 from $188 million for the same period in 2008. The cost of products sold in both 2009 and 2008 was impacted by the curtailment of production from the Port Hope UF6 conversion plant. In the first half of 2009, the plant was shutdown due to the unavailability of HF, while in 2008 operations were suspended to allow for the cleanup of contaminated soil. All operating costs associated with the UF6 conversion plant were expensed as incurred in the first half of 2009 ($18 million) and the first nine months of 2008 ($43 million).

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UF6 Conversion Market Update Spot market UF6 conversion prices declined over the quarter due to the abundance of UF6 supplies on the spot market, as well as the likelihood of US government (DOE) inventory sales (which include conversion). Outlined below are the industry average spot market prices (TradeTech and UxC) for North American and European conversion services as at the dates specified.

Sept. 30/09 June 30/09 Sept. 30/08 June 30/08 Average spot market price ($US/kgU)

• North America • Europe

6.25 8.25

7.00 8.50

9.50 10.75

9.50 10.75

Long-term market UF6 conversion prices declined over the quarter. Outlined below are the industry average long-term prices (TradeTech and UxC) for North American and European conversion services as at the dates specified.

Sept. 30/09 June 30/09 Sept. 30/08 June 30/08 Average long-term price ($US/kgU)

• North America • Europe

11.75 13.13

12.25 13.38

12.25 13.25

12.25 13.25

Fuel Services Operations Update Production Refining At our Blind River refinery, we produced 1.9 million kgU in the third quarter of 2009 compared to 1.1 million kgU for the third quarter of 2008. Total UO3 production for the first nine months of 2009 was 9.0 million kgU compared to 7.2 million kgU in the first nine months of 2008. Conversion Services and Fuel Manufacturing Our Port Hope conversion services, fuel manufacturing production and SFL supply totalled 4.1 million kgU in the third quarter of 2009 compared to 1.8 million kgU in the third quarter of 2008. Port Hope conversion services, fuel manufacturing production and SFL supply was 8.4 million kgU for the first nine months of 2009 compared to 5.7 million kgU for the same period in 2008. We expect continued strong performance at the Port Hope conversion facility for the remainder of the year. Deliveries of HF from a second supplier are arriving at the conversion facility. At Cameco Fuel Manufacturing, the collective agreement with unionized employees expired on June 1, 2009. Negotiations broke down in early September and the union has been on strike since September 5, 2009.

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NUCLEAR ELECTRICITY GENERATION Highlights

Bruce Power Limited Partnership (100% basis)



2009 2008 2009 2008 Output - terawatt hours (TWh) 6.2 6.8 18.2 17.7 Capacity factor (%)1 86 94 86 82 Realized price ($/MWh)2 66 59 64 57 Average Ontario electricity spot price ($/MWh) 22 51 29 49

($ millions) Electricity revenue3 458 405 1,218 1,010

210 198 687 693 Operating costs4 Cash costs - operating & maintenance - fuel - supplemental rent5 Non cash costs (amortization)

125 22 29 34

119 19 29 31

432 67 88 100

461 55 87 90

Income before interest and finance charges 248 207 531 317

Interest and finance charges (4) (8) 3 30 Earnings before taxes 252 215 528 287 Cash from operations 206 181 525 371 Capital expenditures 34 23 83 66 Operating costs ($/MWh)2 30 29 36 39 Distributions 120 210 390 350 1 Capacity factor for a given period represents the amount of electricity actually produced for sale as a percentage of the amount

of electricity the plants are capable of producing for sale. 2 Per MWh calculations for realized price and operating costs for the third quarter and year to date include actual generation

volumes and deemed generation of 0.8 TWh. 3 Electricity revenue for BPLP is comprised of spot sales, revenue recognized under BPLP’s agreement with the OPA, and

payments received under BPLP’s financial contracts. 4 Net of cost recoveries. 5 Supplemental rent is about $28.3 million per operating reactor for 2009. In the third quarter of 2009, BPLP generated cash from operations of $206 million compared to $181 million in the third quarter of 2008. The increase reflects a higher average realized electricity price, partially offset by higher working capital balances and higher operating costs. BPLP distributed $120 million to the partners in the third quarter, with our share being $38 million.

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Cameco’s Earnings from BPLP Three months ended

September 30 Nine months ended

September 30 ($ millions) 2009 2008 2009 2008

BPLP’s earnings before taxes (100%) 252 215 528 287 Cameco’s share of pre-tax earnings before adjustments 80 68 167 91

Proprietary adjustments (2) (7) (5) (5) Pre-tax earnings from BPLP 78 61 162 86 Third Quarter Earnings Before Taxes Our pre-tax earnings from BPLP amounted to $78 million during the third quarter compared to $61 million for the same period in 2008. This increase was due to increased revenue, partially offset by higher operating costs. Output BPLP achieved an adjusted capacity factor of 97% in the third quarter, which includes actual generation and deemed generation of 0.8 TWh. The deemed generation resulted from the B units having their power output reduced in response to dispatch orders from the market operator driven by periods of excess baseload generation in Ontario. Excluding deemed generation, the capacity factor was 86% in the third quarter of 2009 compared to 94% in the same period of 2008. During the third quarter of 2009, BPLP’s units generated 6.2 TWh of electricity compared to 6.8 TWh for the same period in 2008. Revenue and Realized Price For the third quarter of 2009, BPLP’s electricity revenue increased to $458 million from $405 million over the same period in 2008 due to a higher realized price. The realized price, which reflects spot sales, revenue recognized under BPLP’s agreement with the OPA and financial contract revenue, averaged $66 per MWh in the quarter, 12% higher than the realized price for the third quarter of 2008. The increase is largely the result of recognizing revenue of $205 million (our share, $65 million) under the agreement with the OPA during the quarter. During the quarter, the Ontario electricity spot price averaged $22 per MWh compared to $51 per MWh in the third quarter of 2008. Electricity prices in the Ontario market have been trending lower due primarily to reduced industrial demand, increased generation and low fossil fuel prices. During the third quarter of 2009, about 51% of BPLP output was covered by financial contracts, down from the 67% level during the same period in 2008. Costs Operating costs (including amortization) were $210 million in the third quarter of 2009, up 6% compared to the same period of 2008 due to additional maintenance work and increased fuel and amortization costs. About 95% of BPLP’s operating costs are fixed. As such, most of the costs

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are incurred whether the plant is operating or not. On a per MWh basis, the operating cost in the third quarter of 2009 was $30 compared to $29 in the third quarter of 2008 due to the higher costs and lower generation volume. Nine Months Ended September 30, 2009 Earnings Before Taxes Our pre-tax earnings from BPLP for the first nine months of 2009 amounted to $162 million compared to $86 million in the same period of 2008. The increase is attributable to higher revenues. Output For the first nine months of the year, BPLP’s units achieved an adjusted capacity factor of 90%, which includes actual generation and deemed generation of 0.8 TWh. Excluding deemed generation, the capacity factor was 86% compared with 82% in the same period last year. These units produced 18.2 TWh during the first nine months of 2009, an increase of 0.5 TWh over the same period last year. The increase is due primarily to fewer outage days in 2009 compared to 2008. Revenue and Realized Price For the first nine months of the year, BPLP’s electricity revenue increased to $1,218 million from $1,010 million over the same period in 2008 as a result of increased generation and higher realized prices. The realized price, which reflects spot sales, revenue recognized under BPLP’s agreement with the OPA and financial contract revenue, averaged $64 per MWh for the first nine months of the year, 12% higher than the realized price in the same period last year. The increase is largely the result of recognizing revenue of $377 million under the agreement with the OPA for the first nine months of the year. During the first nine months of 2009, the Ontario electricity spot price averaged $29 per MWh, significantly lower than the average of $49 per MWh from the same period of 2008. Costs For the first nine months of 2009, operating costs were $687 million, compared with $693 million in the same period in 2008. This decrease primarily reflects lower staff costs and fewer forced outages. On a per MWh basis, the operating cost for the first nine months of 2009 was $36 compared to $39 in the same period last year.

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GOLD We own approximately 49% of and have voting control over approximately 53% of Centerra’s shares. Centerra is listed on the Toronto Stock Exchange under the symbol CG. Centerra owns and operates two gold mines: Kumtor, which is located in the Kyrgyz Republic and Boroo located in Mongolia. Financial Highlights



2009 2008 2009 2008 Revenue ($ millions) 176 143 427 399 Gross profit ($ millions) 40 40 21 116 Gross profit % 23 28 5 29 Realized price ($US/ounce) 959 860 928 884 Sales volume (ounces) 166,000 162,000 390,000 446,000 Gold production (ounces)1 166,000 186,000 380,000 465,000

1 Represents 100% of production from the Kumtor and Boroo mines. Gold Results Third Quarter For the three months ended September 30, 2009, revenue from our gold business increased by $33 million to $176 million compared to the third quarter of 2008 due to a 12% increase in the US dollar selling price and a 3% increase in sales volume. Centerra’s cost of product sold increased for the quarter and nine months ended September 30, 2009 compared to 2008 as a result of higher labour costs and an increase in the cost of supplies. In addition, the cost of product sold was impacted by recognition of revenue-based taxes in 2009. Centerra produced 166,000 ounces of gold in the third quarter of 2009, which was 20,000 ounces lower than the 186,000 ounces of gold reported in 2008. Production from the Kumtor mine was unchanged at 134,000 ounces as ore grade, 3.5 grams per tonne (g/t), was similar to the third quarter of 2008. Production was lower at the Boroo mine, amounting to 32,000 ounces compared to 52,000 a year earlier, due mainly to the operational shutdown caused by a labour strike at the mine and the subsequent suspension of Boroo’s main operating licences. The average spot market gold price during the third quarter of 2009 was $960 (US) per ounce, an increase of 10% compared to $872 (US) per ounce in the third quarter of 2008. Nine Months Ended September 30, 2009 For the nine months ended September 30, 2009, revenue from our gold business increased by $28 million to $427 million compared to the first nine months of 2008 due to a 5% increase in

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the US dollar selling price, partially offset by a 13% decline in sales volumes. Revenues were also influenced by an improved Cdn/US exchange rate that averaged $1.17 in the first nine months of 2009 compared to $1.02 in 2008. Centerra produced 380,000 ounces of gold in the first nine months of 2009, which was 85,000 ounces less than the 465,000 ounces of gold reported for the same period in 2008. The Kumtor mine saw production decrease to 278,000 ounces from 320,000 ounces in 2008 as the result of a lower ore grade, averaging 2.7 g/t in the first nine months of 2009 compared to the 3.2 g/t milled in 2008. Production was also lower at the Boroo mine, amounting to 102,000 ounces compared to 145,000 a year earlier, due mainly to the operational shutdown caused by a labour strike at the mine and the subsequent suspension of Boroo’s main operating licences. Kyrgyz Republic Kumtor Operations Update During the third quarter of 2009, continued movement of waste and ice from the southeast wall into the Kumtor open pit required the mining of ice and removal of waste which reduced the production of ore and delayed access to the high-grade component of the SB zone. Centerra is working to further stabilize this advanced creep and has expedited a plan to manage accelerated ice and waste movement. While work is planned over the balance of 2009 to sustain the cutback of the ice creep into the pit, there is no guarantee that these efforts will prevent further negative impact on Centerra’s expected results. Maintenance work to replace the Kumtor ball mill ring gear and changeout of the SAG mill liner has been scheduled for the second quarter of 2010. If in either case, earlier replacement is required, an unplanned shutdown of the mill would be required and would have an adverse impact on Centerra’s production, costs and earnings in 2009. In the third quarter of 2009, exploration drilling continued in the Kumtor central pit to test the southwest extension of the SB zone within and outside of the current planned open pit. Results of the 2009 drilling in the SB zone area will extend the resource model beyond the current planned pit design. Drilling also focused on confirming the grade and extent of potential high-grade underground mineable mineralization in the Stockwork zone below the current planned open pit. Mongolia Boroo Operations Update On October 23, 2009, Centerra received a claim for compensation from the Mongolian governmental authorities related to certain mineral reserves. Centerra disputes the claim. While Centerra believes that the issues raised by the claim will be resolved through negotiation with the authorities without a material impact on Centerra, there can be no assurances that this will be the case. For further information, refer to note 15 of our third quarter unaudited consolidated financial statements.

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LIQUIDITY AND CAPITAL RESOURCES During the quarter, we issued $500 million of 10-year senior unsecured debentures. The debentures bear interest at 5.67% per annum and mature on September 2, 2019. Net proceeds from the debenture issuance are being used to refinance existing indebtedness and for general corporate purposes. Following the successful debenture offering, we terminated our $500 million, 364-day unsecured revolving credit facility that had a maturity date of June 16, 2010. Credit Ratings There has been no change to our credit ratings as discussed in our annual MD&A. Debt In addition to cash from operations, debt is used to provide liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $1,200 million, which include the following: • A $500 million, unsecured revolving credit facility that matures November 30, 2012. Upon

mutual agreement, the facility can be extended for an additional year on the anniversary date. In addition to direct borrowings under the facility, up to $100 million can be used for the issuance of letters of credit and, to the extent necessary, up to $400 million is kept available to provide liquidity support for our commercial paper program. The facility ranks equally with all of our other senior debt. At September 30, 2009, there was no amount outstanding under this credit facility. However, at September 30, 2009, there was $126 million outstanding under our commercial paper program.

• A $100 million, unsecured revolving credit facility, maturing February 5, 2010, and

extendable for two additional 364-day terms upon mutual agreement with the lender. At September 30, 2009, there was no amount outstanding under this credit facility.

• Approximately $600 million in short-term borrowing and letters of credit provided by

various financial institutions. These facilities are predominantly used to fulfill regulatory requirements to provide financial assurance for future decommissioning and reclamation of our operating sites and as overdraft protection. At September 30, 2009, outstanding letters of credit amounted to $593 million.

We have $800 million outstanding in senior unsecured debentures, which includes: • $300 million, bearing interest at a rate of 4.7% per annum and maturing September 16, 2015. • $500 million, bearing interest at a rate of 5.67% per annum and maturing September 2, 2019. We have issued a promissory note payable to GE-Hitachi Global Enrichment, LLC in the amount of $73 million (US) to support future development of its business.

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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 September 30, 2009, we met these financial covenants and do not expect our operating and investment activities in 2009 to be constrained by them. Contractual Cash Obligations There have been no material changes to our contractual cash obligations since December 31, 2008, including payments due for the next five years and thereafter. For further information on these contractual obligations, refer to our annual MD&A. For further information regarding commitments and contingencies, refer to notes 9, 14 and 15 of our third quarter unaudited consolidated financial statements. Commercial Commitments There have been no material changes to our commercial commitments since December 31, 2008. For further information on these commercial commitments, refer to our annual MD&A. OUTSTANDING SHARE DATA At September 30, 2009, there were 392,654,873 common shares and one Class B share outstanding. In addition, there were 8,139,992 stock options outstanding with exercise prices ranging from $5.88 to $54.50 per share. CONTROLS AND PROCEDURES As of September 30, 2009, 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 September 30, 2009, 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 the company files and submits 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 September 30, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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CHANGES IN ACCOUNTING POLICY NEW ACCOUNTING PRONOUNCEMENTS Goodwill and Intangible Assets Effective January 1, 2009, we adopted the new Canadian standard, Handbook Section 3064, Goodwill and Intangible Assets, which replaces Handbook Section 3062, Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs. The standard introduces guidance for the recognition, measurement and disclosure of goodwill and intangible assets, including internally generated intangible assets. The standard harmonizes Canadian standards with International Financial Reporting Standards and applies to annual and interim financial statements for fiscal years beginning on or after October 1, 2008. The new standard had no significant impact on our consolidated financial statements. International Financial Reporting Standards (IFRS) The Accounting Standards Board has announced that Canadian publicly accountable enterprises will be required to adopt IFRS effective January 1, 2011. Although IFRS employs a conceptual framework that is similar to Canadian GAAP, there are significant differences in recognition, measurement and disclosure. We have undertaken a project to assess the potential impacts of the transition to IFRS and have established a project team led by management to plan for and achieve a smooth transition to IFRS. The team has developed a detailed project plan to ensure compliance with the new standards. Regular progress reports on the status of our IFRS implementation project are provided to senior management and to the audit committee of the board. A major public accounting firm has been engaged to provide technical accounting advice and project management guidance in the conversion to IFRS. Our implementation project consists of three principal phases: Phase 1: Preliminary Study and Diagnostic – This phase included performing a high-level impact assessment to identify key areas that may be impacted by the adoption of IFRS. This analysis is complete and resulted in prioritization of areas to be evaluated in the next phase of the project plan. The information obtained from the assessment was also used to develop a detailed plan for convergence and implementation. During phase 1, an analysis was also performed to assess whether information technology systems used to collect and report financial data required modification in order to meet new reporting requirements under IFRS. The necessary systems modifications have been tested and implemented as of June 30, 2009. Phase 2: Detailed Component Evaluation – In this phase, further evaluation of the financial statement areas impacted by IFRS will be completed. This will involve a more detailed, systematic gap analysis of accounting and disclosure differences between Canadian GAAP and IFRS. This detailed assessment will facilitate final decisions around accounting policies and overall conversion strategy. This phase also involves specification of changes required to existing business processes. Phase 3: Embedding – This phase includes execution of changes to business processes impacted by our transition to IFRS and formal approval of recommended accounting policy changes. Also included in this phase is the delivery of necessary IFRS training to our audit committee of the

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board, board of directors and staff. This phase will culminate with the collection of financial information necessary to compile IFRS compliant financial statements and audit committee approval of IFRS financial statements commencing in 2011. We completed phase 1 in June 2008 and are now in the detailed component evaluation phase, with some work also being performed in the embedding phase. Our analysis of the areas that may be impacted by the adoption of IFRS has identified a number of differences. The training that we have delivered thus far has focused on updating those individuals whose responsibilities are directly impacted by the changes being implemented as a result of the conversion to IFRS. We have held information sessions for both the audit committee of the board and the board of directors on the more significant accounting policy choices and IFRS 1 elections available to us, as well as on IFRS financial statement format and disclosures. We are currently assessing the impact of the adoption of IFRS on our results of operations, financial position and financial statement disclosures. In addition, we continue to assess the impact of the conversion on internal controls over financial reporting and disclosure controls and procedures. We will continue to invest in training and resources throughout the transition period. Financial Instruments – Disclosures In June 2009, the CICA issued amendments to Handbook Section 3862, Financial Instruments – Disclosures requiring enhanced disclosures related to liquidity risk and new disclosures on fair value measurement of financial instruments. These requirements harmonize Canadian standards with IFRS and apply to annual financial statements for fiscal years ending after September 30, 2009. We are assessing the impact the new standard on our consolidated financial statements.

USE OF NON-GAAP FINANCIAL MEASURES Adjusted net earnings, a non-GAAP measure, should be considered as supplemental in nature and not a substitute for related financial information prepared in accordance with GAAP. Consolidated net earnings are adjusted in order to provide a more meaningful basis for period-to-period comparisons of the financial results. The following table outlines the adjustment to net earnings. Adjusted Net Earnings



($ millions) 2009 2008 2009 2008 Net earnings (per GAAP) 172 135 501 419 Adjustments (after tax) Loss (gain) on restructuring of the gold business 33 (2) 17 (29)

Stock option expense (recovery)1 - (52) - (34) Losses (gains) on financial

instruments (101) 26 (184) 38

Writedown of investments - 20 - 20

Adjusted net earnings 104 127 334 414 1 Late in 2008, we amended our stock option program and began accounting for our options using their fair value at the grant

date. Under this method, our stock option expense is highly predictable. For this reason, we will not be adjusting our net earnings for stock option expense in 2009.

QUALIFIED PERSONS The disclosure of scientific and technical information regarding the following Cameco properties in this MD&A was prepared by or under the supervision of the following qualified persons for the purpose of National Instrument 43-101:

Qualified Persons Properties • David Bronkhorst, general manager, McArthur River operation,

Cameco • Les Yesnik, general manager, Key Lake operation, Cameco

McArthur River/Key Lake

• Grant Goddard, general manager, Cigar Lake project, Cameco Cigar Lake • Ian Atkinson, vice-president, exploration, Centerra Gold Kumtor

CAUTION REGARDING FORWARD-LOOKING INFORMATION AND STATEMENTS Statements contained in this MD&A which are not current statements or historical facts are “forward-looking information” (as defined under Canadian securities laws) and “forward-looking statements” (as defined in the US Securities Exchange Act of 1934, as amended) which may be material and that involve risks, uncertainties and other factors that could cause actual results to differ materially from those expressed or implied by them. Sentences and phrases containing words such as “believe”, “estimate”, “anticipate”, “plan”, “outlook”, “predict”, “goals”,

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“targets”, “forecast”, “projects”, “may”, “hope”, “can”, “will”, “shall”, “should”, “expect”, “intend”, “is designed to”, “continues”, “with the intent”, “potential”, “strategy” and the negative of these words, or variations of them, or comparable terminology that does not relate strictly to current or historical facts, are all indicative of forward-looking information and statements. Examples of forward-looking information and statements include, but are not limited to: our consolidated outlook for the year 2009 and related discussion; future earnings sensitivity to changes in the exchange rate; price sensitivity analysis for uranium, electricity and gold; the uranium production outlook for 2009 to 2013 and related discussion; our expected uranium production quantities for 2009; the uranium price sensitivity table for 2009 to 2013 and related discussion; our expectations regarding the expected start date and production levels for the zone 2, panel 5 chamber at McArthur River, and the expected timing for completion of freeze hole drilling, and the commencement of freezing and initial production, for lower zone 4 at McArthur River; our expectation that adopting the new tax code will not have a material impact on Inkai; and our expectation that Cameco’s operating and investing activities in 2009 will not be constrained by the financial covenants in our general credit facilities. The material risk factors that could cause actual results to differ materially from the forward-looking information and statements contained in this MD&A and the material risk factors or assumptions that were used to develop them include, without limitation: our assumptions regarding production levels, sales volumes, purchases and prices, which are subject to the risk that our assumptions are incorrect; the risk of volatility and sensitivity to market prices for our products and services, which we have assumed will remain relatively constant; the assumption regarding the B units of BPLP reaching their targeted capacity factor and that there will be no significant changes in current estimates for costs and prices, and the risk that those assumptions vary adversely; the risk of material adverse changes in foreign currency exchange rates, interest rates and costs, which we have assumed will remain constant or improve in our favour; our assumptions regarding production, cost, remediation, decommissioning, reclamation, mineral reserve and tax estimates, and the risk that our assumptions are incorrect; the risk of material litigation, arbitration or regulatory proceedings and their adverse outcome, which we have assumed will not occur; the risk we may not be able to enforce legal rights which we have assumed to be enforceable; environmental and safety risks, which we have assumed will not adversely affect us; unexpected or challenging geological, hydrological or mining conditions which deviate significantly from our assumptions regarding those conditions; political risks arising from operating in certain developing countries, which we have assumed will not occur; the risk of adverse changes in government legislation, regulations and policies, which we have assumed will not occur; the risk of uranium and conversion service providers’ failure to fulfill delivery commitments, which we have assumed will not occur; failure to obtain or maintain necessary permits, licences, and approvals from government authorities, which we have assumed may be obtained and maintained; the risk of natural phenomena such as fire, flooding or earthquakes, which we have assumed will not occur; our assumptions regarding the ability of the company’s and customers’ facilities to operate without disruption, including as a result of strikes, lockouts, equipment failure or other causes and the risk that such disruptions may occur; assumptions regarding the availability of reagents, equipment, operating parts, and supplies critical to production, which are subject to the risk that our assumptions may be incorrect; assumptions regarding uranium spot prices, gold spot prices, Ontario electrical spot prices and the US/Canadian spot exchange rate, which are subject to the risk of fluctuations that would be materially adverse to us; the assumptions and risk factors regarding uranium price sensitivity set out under the heading “Uranium Price Sensitivity (2009 to 2013)”; the schedule for the development and rampup of production from Inkai is achieved, which is subject to the risk of delay; the successful transition to new mining areas at McArthur River commencing in 2009, which is subject to various expected and unanticipated risks; the dewatering and depressurization programs at Kumtor continue to produce the expected results and the water management systems work as planned, which is subject to various expected and unanticipated risks; Centerra is successful in mitigating the continued movement of waste and ice into the Kumtor open pit, which is subject to various expected and unanticipated risks; the success and timely completion of planned development and remediation projects, including the remediation of and return to pre-flood construction at Cigar Lake, and the risk of delay or ultimate lack of success; the risk of a significant decline in general economic conditions, which we have assumed will not occur; and other development, operating, environmental and safety risks. There may be other factors that cause actions, events or results not to be as anticipated, estimated or intended. These factors are not intended to represent a complete list of the material risk factors that could affect Cameco. Additional risk factors are noted in Cameco’s current annual information form and current annual, and first and second quarter, MD&A.

- 30 -

The forward-looking information and statements included in this MD&A represent Cameco’s views as of the date of this MD&A and should not be relied upon as representing Cameco’s views as of any subsequent date. While Cameco anticipates that subsequent events and developments may cause its views to change, Cameco specifically disclaims any intention or obligation to update forward-looking information and statements, whether as a result of new information, future events or otherwise, except to the extent required by applicable securities laws. Forward-looking information and statements contained in this MD&A about prospective results of operations, financial position or cash flows that are based upon assumptions about future economic conditions and courses of action is presented for the purpose of assisting Cameco’s shareholders in understanding management’s current views regarding those future outcomes, and may not be appropriate for other purposes. There can be no assurance that forward-looking information and statements will prove to be accurate, as actual results and future events could vary, or differ materially, from those anticipated in them. Further, expected future production estimates are inherently uncertain, particularly in the latter years of the forecast, and could materially change over time. Accordingly, readers of this MD&A should not place undue reliance on forward-looking information and statements. Forward-looking information and statements for time periods subsequent to 2009 involve greater risks and require longer-term assumptions and estimates than those for 2009, and are consequently subject to greater uncertainty. Therefore, the reader is especially cautioned not to place undue reliance on such long-term forward-looking information and statements. ADDITIONAL INFORMATION Additional information on Cameco, including its annual information form, is available on SEDAR at sedar.com and the company’s website at cameco.com.

- End -

Cameco CorporationHighlights(Unaudited)

Sept 30/09 Sept 30/08 Sept 30/09 Sept 30/08

Financial (in millions) Revenue $694 $729 $2,083 $1,941Earnings from operations 224 176 585 459 Net earnings 172 135 501 419 Adjusted net earnings 104 127 334 414 Cash provided by operations 248 109 565 368 Working capital (end of period) 1,267 300 Net debt to capitalization 10% 25%

Per common shareNet earnings - Basic $0.44 $0.39 $1.30 $1.22

- Diluted 0.44 0.39 1.29 1.21 - Diluted, adjusted 0.26 0.37 0.86 1.19

Dividend 0.06 0.06 0.18 0.18

Weighted average number of paid common shares outstanding (in thousands) 392,613 345,830 386,355 344,906

Uranium price informationAverage uranium spot price for the period (US$/lb) $45.29 $60.50 $46.10 $65.11Average uranium realized price for the period (US$/lb) 34.24 37.88 37.26 42.69Average uranium realized price for the period (Cdn$/lb) 39.18 39.90 45.80 44.42

Sales volumesUranium (in thousands lbs U3O8) 8,280 9,846 23,883 23,640Fuel services (tU) 2,833 3,748 8,853 10,219Gold (troy ounces) 166,000 162,000 390,000 446,000Electricity (TWh) 1.9 2.2 5.8 5.6

Note: Currency amounts are expressed in Canadian dollars unless stated otherwise.

Cameco'sCameco Production Share Sept 30/09 Sept 30/08 Sept 30/09 Sept 30/08

Uranium production (in thousands lbs U3O8)McArthur River 69.8% 3,758 2,088 9,325 8,471Rabbit Lake 100.0% 918 202 2,415 1,715 Crow Butte 100.0% 198 148 554 435Smith Ranch Highland 100.0% 410 278 1,300 954Inkai 60.0% 343 64 536 192 Total 5,627 2,780 14,130 11,767

Fuel services (tU) (i) 100.0% 4,088 1,838 8,449 5,745

Gold (troy ounces)Kumtor 100.0% 134,000 134,000 278,000 320,000Boroo 100.0% 32,000 52,000 102,000 145,000 Total 166,000 186,000 380,000 465,000

(i) Includes toll conversion supplied by Springfield Fuels Ltd.

Three Months Ended

Three Months Ended

Nine Months Ended

Nine Months Ended

Cameco CorporationConsolidated Statements of Earnings(Unaudited)($Cdn Thousands)


Revenue fromProducts and services $694,103 $728,896 $2,083,080 $1,941,474

ExpensesProducts and services sold (i) 407,733 412,152 1,252,811 1,056,374Depreciation, depletion and reclamation 97,329 89,196 264,892 203,178Administration [note 11] 42,347 (32,467) 120,158 61,251Exploration [note 9] 18,204 21,892 52,507 53,656Research and development [note 9] (2,299) 1,245 (86) 4,147Interest and other [note 8] (125,816) 56,944 (212,996) 89,362Cigar Lake remediation [note 9] 2,927 2,150 13,119 8,883 Restructuring of gold business [note 14] 26,900 2,200 7,800 8,800 Loss (gain) on sale of assets 2,337 (129) 183 (3,206)

469,662 553,183 1,498,388 1,482,445

Earnings from operations 224,441 175,713 584,692 459,029

Equity in loss of associated companies (4,686) (2,428) (24,706) (6,232)Write-down of investments - (23,571) - (23,571)

Earnings before income taxes and minority interest 219,755 149,714 559,986 429,226

Income tax expense (recovery) [note 9] 37,638 6,021 77,059 (16,677)Minority interest 10,002 8,242 (18,035) 26,724

Net earnings $172,115 $135,451 $500,962 $419,179

Basic earnings per common share [note 10] $0.44 $0.39 $1.30 $1.22

Diluted earnings per common share [note 10] $0.44 $0.39 $1.29 $1.21

(i) Excludes depreciation, depletion and reclamation expenses of: $94,753 $86,963 $256,939 $196,543

Nine Months EndedThree Months Ended

See accompanying notes to consolidated financial statements

Cameco CorporationConsolidated Balance Sheets(Unaudited)($Cdn Thousands)

Sept 30/09 Dec 31/08

AssetsCurrent assets

Cash and cash equivalents $669,732 $269,176Accounts receivable 314,099 568,340Inventories [note 3] 487,412 470,649Supplies and prepaid expenses 279,118 301,937Current portion of long-term receivables, investments and other [note 5] 196,010 49,836

1,946,371 1,659,938

Property, plant and equipment 4,485,288 4,416,293Intangible assets and goodwill 254,666 283,344Long-term receivables, investments and other [note 5] 653,031 628,972Long-term inventories [note 3] 24,505 22,054

5,417,490 5,350,663

Total assets $7,363,861 $7,010,601

Liabilities and Shareholders' EquityCurrent liabilities

Accounts payable and accrued liabilities $454,336 $580,903Short-term debt 78,640 89,817 Dividends payable 23,559 21,943Current portion of long-term debt 11,344 10,175 Current portion of other liabilities 21,077 117,222Future income taxes 90,666 68,857

679,622 888,917

Long-term debt [note 6] 1,082,096 1,212,982Provision for reclamation 341,062 353,344Other liabilities 177,044 179,880Future income taxes 94,058 81,352

2,373,882 2,716,475

Minority interest 697,295 779,203

Shareholders' equityShare capital 1,513,733 1,062,714Contributed surplus 136,369 131,858Retained earnings 2,583,617 2,153,315Accumulated other comprehensive income 58,965 167,036

4,292,684 3,514,923

Total liabilities and shareholders' equity $7,363,861 $7,010,601

Commitments and contingencies [notes 9,14,15]

As At


Cameco CorporationConsolidated Statements of Shareholders' Equity(Unaudited)($Cdn Thousands)

Sept 30/09 Sept 30/08

Share capitalBalance at beginning of period $1,062,714 $819,268Stock option plan 5,487 735 Conversion of debentures - 242,352 Equity issuance [note 7] 445,532 -

Balance at end of period $1,513,733 $1,062,355

Contributed surplusBalance at beginning of period $131,858 $119,531Stock-based compensation 4,917 16,213 Conversion of debentures - (30,431) Options exercised (406) -

Balance at end of period $136,369 $105,313

Retained earningsBalance at beginning of period $2,153,315 $1,788,418Net earnings 500,962 419,179 Dividends on common shares (70,660) (63,275)

Balance at end of period $2,583,617 $2,144,322

Accumulated other comprehensive income (loss)Balance at beginning of period $167,036 $25,433Other comprehensive income (108,071) 21,866

Balance at end of period $58,965 $47,299

Total retained earnings and accumulated other comprehensive income $2,642,582 $2,191,621

Shareholders' equity at end of period $4,292,684 $3,359,289

Nine Months Ended


Cameco CorporationConsolidated Statements of Comprehensive Income(Unaudited)($Cdn Thousands)


Net earnings $172,115 $135,451 $500,962 $419,179Other comprehensive income (loss), net of taxes [note 9]

Unrealized foreign currency translation (losses) gains (89,436) 48,060 (137,289) 70,767 Gains on derivatives designated as cash flow hedges 29,983 67,622 114,385 23,157 Gains on derivatives designated as cash flow hedges

transferred to net earnings (32,481) (23,800) (87,317) (78,440) Unrealized gains (losses) on assets available-for-sale 390 (4,592) 2,150 (12,995) Losses on assets available-for-sale transferred to net earnings - 19,377 - 19,377

Other comprehensive income (91,544) 106,667 (108,071) 21,866

Total comprehensive income $80,571 $242,118 $392,891 $441,045

Cameco CorporationConsolidated Statement of Accumulated Other Comprehensive Income(Unaudited)($Cdn Thousands)

CurrencyTranslation Cash Flow Available-For-

(net of related income taxes)[note 9] Adjustment Hedges Sale Assets Total

Balance at December 31, 2008 $66,642 $101,654 ($1,260) $167,036Change in unrealized foreign currency translation losses (137,289) - - (137,289) Change in gains on derivatives designated as cash flow hedges - 114,385 - 114,385 Change in gains on derivatives designated as cash flow hedges

transferred to net earnings - (87,317) - (87,317) Change in unrealized gains on available-for-sale securities - - 2,150 2,150

Balance at September 30, 2009 ($70,647) $128,722 $890 $58,965

Balance at December 31, 2007 ($150,935) $182,734 ($6,366) $25,433Change in unrealized foreign currency translation gains 70,767 - - 70,767 Change in losses on derivatives designated as cash flow hedges - 23,157 - 23,157 Change in gains on derivatives designated as cash flow hedges

transferred to net earnings - (78,440) - (78,440) Change in unrealized losses on available-for-sale securities - - (12,995) (12,995) Change in losses on available-for-sale securities

transferred to net earnings - - 19,377 19,377

Balance at September 30, 2008 ($80,168) $127,451 $16 $47,299



Cameco CorporationConsolidated Statements of Cash Flows(Unaudited)($Cdn Thousands)


Operating activities Net earnings $172,115 $135,451 $500,962 $419,179

Items not requiring (providing) cash:Depreciation, depletion and reclamation 97,329 89,196 264,892 203,178 Provision for future taxes [note 9] 29,449 (28,141) 19,141 (93,849) Deferred gains (8,790) (14,168) (33,102) (93,515) Unrealized (gains) losses on derivatives (84,296) 14,026 (197,315) 32,431 Stock-based compensation [note 11] 774 16,552 4,917 16,213 Loss (gain) on sale of assets 2,337 (129) 183 (3,206) Equity in loss of associated companies 4,686 2,428 24,706 6,232 Write-down of investments - 23,571 - 23,571 Restructuring of gold business [note 14] 26,900 2,200 7,800 8,800 Minority interest 10,002 8,242 (18,035) 26,724

Other operating items [note 13] (2,271) (139,872) (9,490) (177,512)

Cash provided by operations 248,235 109,356 564,659 368,246

Investing activitiesAdditions to property, plant and equipment (128,640) (524,318) (366,732) (764,517) Increase in long-term receivables, investments and other (12,096) (33,724) (35,832) (191,084) Proceeds on sale of property, plant and equipment 52 33,029 3,685 36,102

Cash used in investing (140,684) (525,013) (398,879) (919,499)

Financing activitiesDecrease in debt (237,713) (25,997) (607,367) (30,326) Increase in debt - 484,346 - 646,543 Issue of debentures, net of issue costs [note 6] 495,818 - 495,818 - Issue of shares, net of issue costs [note 7] - 34 440,150 735 Issue of shares, stock option plan 1,023 - 5,081 - Dividends (23,553) (20,668) (69,044) (58,554)

Cash provided by financing 235,575 437,715 264,638 558,398

Increase in cash during the period 343,126 22,058 430,418 7,145 Exchange rate changes on foreign currency cash balances (22,748) 6,035 (29,862) 9,899 Cash and cash equivalents at beginning of period 349,354 120,883 269,176 131,932

Cash and cash equivalents at end of period $669,732 $148,976 $669,732 $148,976

Cash and cash equivalents comprised of:Cash $87,995 $64,878Cash equivalents 581,737 84,098

$669,732 $148,976

Supplemental cash flow disclosureInterest paid $10,894 $18,832 $31,889 $41,715Income taxes paid $7,190 $16,766 $64,498 $118,026



Cameco Corporation Notes to Consolidated Financial Statements (Unaudited)

1. Accounting Policies These consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) and follow the same accounting principles and methods of application as the most recent annual consolidated financial statements except for the recent accounting standards adopted described below. Since the interim financial statements do not include all disclosures required by GAAP, they should be read in conjunction with Cameco’s annual consolidated financial statements included in the 2008 annual financial review. Certain comparative figures for the prior period have been reclassified to conform to the current period’s presentation. (a) Goodwill and Intangible Assets

Effective January 1, 2009, Cameco adopted the new Canadian standard, Handbook Section 3064, Goodwill and Intangible Assets, which replaced Handbook Section 3062, Goodwill and Other Intangible Assets and Section 3450, Research and Development Costs. The standard introduces guidance for the recognition, measurement and disclosure of goodwill and intangible assets, including internally generated intangible assets. The standard also harmonizes Canadian standards with IFRS and applies to annual and interim financial statements for fiscal years beginning on or after October 1, 2008. There was no material impact to previously reported financial statements as a result of the implementation of the new standard.

2. Future Changes in Accounting Policy (a) International Financial Reporting Standards (IFRS)

The Accounting Standards Board (AcSB) has announced that Canadian publicly accountable enterprises will be required to adopt IFRS effective January 1, 2011. Although IFRS employs a conceptual framework that is similar to Canadian GAAP, there are significant differences in recognition, measurement and disclosure. Cameco has undertaken a project to assess the potential impacts of the transition to IFRS and has developed a detailed project plan to ensure compliance with the new standards. Cameco has completed the initial phase of the implementation project including the detailed diagnostic analysis which included a high-level impact assessment to identify key areas that may be impacted by the adoption of IFRS. This analysis resulted in the prioritization of areas to be evaluated in the next phase of the project plan, component evaluation. This phase, which is currently in progress, includes the analysis of accounting policy alternatives available under IFRS as well as the determination of changes required to existing information systems and business processes. As of June 30, 2009, the systems changes necessary to support the IFRS conversion had been fully tested and implemented. Cameco continues to assess the impact of the conversion on internal controls over financial reporting and disclosure controls and procedures and will continue to invest in training and resources throughout the transition period to facilitate a timely conversion. Cameco is currently assessing the impact of the adoption of IFRS on our results of operations, financial position and financial statement disclosures.

(b) Financial Instruments - Disclosures In June 2009, the CICA issued amendments to Handbook Section 3862, Financial Instruments – Disclosures. The amendments provide for enhanced disclosures on liquidity risk and require new disclosures on fair value measurements of financial instruments. These requirements harmonize Canadian standards with IFRS and apply to annual financial statements for fiscal years ending after September 30, 2009. Cameco is assessing the impact the new standard on its consolidated financial statements.


3. Inventories

(thousands) Sept 30/09 Dec 31/08

Uranium Concentrate $286,572 $287,079 Broken ore 22,351 21,396

308,923 308,475

Fuel Services 132,048 89,635

Gold Finished 11,166 18,662 Stockpile 59,780 75,931

70,946 94,593

Total 511,917 492,703 Less: Non-current portion (24,505) (22,054)

Net $487,412 $470,649

As At

The non-current portion of inventory represents values assigned to low-grade stockpiles of gold ore that are not expected to be processed in the next 12 months.

4. Derivatives

The following tables summarize the fair value of derivatives and classification on the balance sheet:

As at September 30, 2009

(thousands) Cameco BPLP Total

Non-hedge derivatives: Embedded derivatives - sales contracts $(3,381) $8,259 $4,878 Foreign currency contracts 87,368 - 87,368 Cash flow hedges: Energy and sales contracts - 143,995 143,995

Net $83,987 $152,254 $236,241

Classification: Current portion of long-term receivables, investments and other [note 5] $99,891 $95,796 $195,687 Long-term receivables, investments and other [note 5] - 57,974 57,974 Current portion of other liabilities (12,394) (1,516) (13,910) Other liabilities (3,510) - (3,510)

Net $83,987 $152,254 $236,241


As at December 31, 2008


Non-hedge derivatives: Embedded derivatives - sales contracts $(8,951) $4,344 $(4,607) Foreign currency contracts (105,125) - (105,125) Cash flow hedges: Energy and sales contracts - 71,116 71,116

Net $(114,076) $75,460 $(38,616)

Classification: Current portion of long-term receivables, investments and other [note 5] $5,793 $43,654 $49,447 Long-term receivables, investments and other [note 5] - 32,340 32,340 Current portion of other liabilities (110,918) (73) (110,991) Other liabilities (8,951) (461) (9,412)

Net $(114,076) $75,460 $(38,616)

The following tables summarize different components of the (gains) and losses on derivatives:

For the three months ended September 30, 2009


Non-hedge derivatives: Embedded derivatives - sales contracts $1,812 $(2,224) $(412) Foreign currency contracts (128,854) 138 (128,716) Cash flow hedges: Energy and sales contracts - 153 153

Net $(127,042) $(1,933) $(128,975)

For the three months ended September 30, 2008


Non-hedge derivatives: Embedded derivatives - sales contracts $4,950 $(4,275) $675 Foreign currency contracts 22,416 - 22,416 Interest rate contracts 906 - 906 Cash flow hedges: Energy and sales contracts - (467) (467) Ongoing hedge inefficiency (467) - (467)

Net $27,805 $(4,742) $23,063


For the nine months ended September 30, 2009


Non-hedge derivatives: Embedded derivatives - sales contracts $(4,307) $(4,292) $(8,599) Foreign currency contracts (193,194) 378 (192,816) Cash flow hedges: Energy and sales contracts - 196 196

Net $(197,501) $(3,718) $(201,219)



Non-hedge derivatives: Embedded derivatives - sales contracts $5,208 $1,291 $6,499 Foreign currency contracts 42,869 - 42,869 Interest rate contracts 906 - 906 Cash flow hedges: Energy and sales contracts - (203) (203) Ongoing hedge inefficiency 2,210 - 2,210

Net $51,193 $1,088 $52,281

Over the next 12 months, based on current exchange rates, Cameco expects an estimated $31,420,000 of pre-tax gains from the foreign currency cash flow hedges to be reclassified through other comprehensive income to net earnings. The maximum length of time Cameco hedges its exposure to the variability in future cash flows related to foreign currency on anticipated transactions is five years.

Over the next 12 months, based on current prices, Cameco expects an estimated $92,540,000 of pre-tax gains from BPLP’s various energy and sales related cash flow hedges to be reclassified through other comprehensive income to net earnings. The maximum length of time BPLP is hedging its exposure to the variability in future cash flows related to electricity prices on anticipated transactions is five years.


5. Long-Term Receivables, Investments and Other

As At(thousands) Sept 30/09 Dec 31/08

Bruce A L.P. (BPLP) Capital lease receivable from BPLP (i) $95,464 $97,044 Derivatives [note 4] 153,770 75,994 Accrued pension benefit asset 30,751 6,061 Kumtor Gold Company (KGC) Reclamation trust fund 7,022 6,219 Equity accounted investments Global Laser Enrichment LLC (privately held) 193,164 240,018 Govi High Power Exploration Inc. (privately held) 27,225 34,442 UNOR Inc. (market value $1,088) 959 1,088 UEX Corporation (market value $47,690) 5,486 6,714 Huron Wind (privately held) 4,111 4,623 Minergia S.A.C. (privately held) 135 534 Available-for-sale securities Western Uranium Corporation (market value $4,301) 4,301 3,296 Cue Resources Ltd. (market value $338) 338 422 Derivatives [note 4] 99,891 5,793 Deferred charges Cost of sales 6,414 6,414 Advances receivable from Inkai JV LLP (ii) 142,919 126,130 Accrued pension benefit asset 4,151 4,815 Other 72,940 59,201

849,041 678,808 Less current portion (196,010) (49,836)

Net $653,031 $628,972

(i) BPLP leases the Bruce A nuclear generating plants and other property, plant and equipment to Bruce A L.P.

under a sublease agreement. Future minimum base rent sublease payments under the capital lease receivable are imputed using a 7.5% discount rate.

(ii) Through an unsecured shareholder loan, Cameco has agreed to fund the development of the Inkai project. The

limit of the loan facility is $370,000,000 (US) and advances under the facility bear interest at a rate of LIBOR plus 2%. At September 30, 2009, $330,000,000 (US) of principal and interest was outstanding (2008 - $257,000,000 (US)), of which 40% represents the joint venture partner’s share. Of the cash available for distribution each year, 80% is to be used to repay the loan until it is repaid in full.

6. Long-Term Debt

Cameco has a $500,000,000 unsecured revolving credit facility that is available until November 30, 2012. In addition to direct borrowings under the facility, up to $100,000,000 can be used for the issuance of letters of credit and, to the extent necessary, up to $400,000,000 may be allocated to provide liquidity support for the company’s commercial paper program. The facility ranks equally with all of Cameco’s other senior debt. At September 30, 2009 there was no amount outstanding under this credit facility. Cameco may borrow directly in the commercial paper market. Commercial paper outstanding at September 30, 2009 was $125,900,000. These amounts, when drawn, are classified as long-term debt. On September 2, 2009, Cameco issued unsecured debentures in the amount of $500,000,000. The debentures bear interest at 5.67% per annum (effective interest rate of 5.78%) and mature on September 2, 2019. The proceeds of the issue after deducting expenses were $495,800,000.


7. Share Capital (a) At September 30, 2009, there were 392,654,873 common shares outstanding. (b) Options in respect of 8,139,992 shares are outstanding under the stock option plan and are exercisable up to

2018. For the quarter ended September 30, 2009, 89,190 options were exercised resulting in the issuance of shares (2008 – 11,280). For the nine months ended September 30, 2009, 269,550 options were exercised resulting in the issuance of shares (2008 – 79,540).

(c) On March 5, 2009, Cameco finalized and issued 26,666,400 common shares pursuant to a public offering for a total consideration of $459,995,000. The proceeds of the issue after deducting expenses, net of taxes, were $445,532,000.

8. Interest and Other

Three Months Ended Nine Months Ended(thousands) Sept 30/09 Sept 30/08 Sept 30/09 Sept 30/08

Interest on long-term debt $6,868 $14,795 $24,263 $36,334Interest on short-term debt 486 3,587 1,905 3,728 Foreign exchange (gains) losses 1,915 28,663 (18,232) 31,385 Losses (gains) on derivatives [note 4] (128,975) 23,063 (201,219) 52,281 Other charges 3,338 1,441 10,302 5,102 Interest income (1,921) (2,516) (4,788) (11,346) Capitalized interest (7,527) (12,089) (25,227) (28,122)

Net $(125,816) $56,944 $(212,996) $89,362

9. Income Tax Expense (Recovery)


Earnings (loss) before income taxes andminority interest Canada $20,820 $(88,092) $75,057 $(205,633) Foreign 198,935 237,806 484,929 634,859

$219,755 $149,714 $559,986 $429,226

Current income taxes (recovery) Canada $(5,141) $14,984 $19,158 $25,659 Foreign 13,331 19,178 38,761 51,513

$8,190 $34,162 $57,919 $77,172Future income taxes (recovery) Canada $35,908 $(27,545) $20,263 $(97,743) Foreign (6,460) (596) (1,123) 3,894

$29,448 $(28,141) $19,140 $(93,849)

Income tax expense (recovery) $37,638 $6,021 $77,059 $(16,677)


In 2008, as part of the ongoing annual audits of Cameco’s Canadian tax returns, Canada Revenue Agency (CRA) disputed the transfer pricing methodology used by Cameco and its wholly-owned Swiss subsidiary, Cameco Europe Ltd. (CEL), in respect of sale and purchase agreements for uranium products. In December 2008, CRA issued a notice of reassessment, which increased Cameco’s 2003 Canadian taxable income by approximately $43,000,000 (which does not result in any cash taxes becoming payable for that year). Cameco believes it is likely that CRA will reassess Cameco’s tax returns for the years 2004 through 2008 on a similar basis.

Late in 2008, CRA’s Transfer Pricing Review Committee decided not to impose a penalty for 2003 based on the documentation that had been submitted by Cameco.

Having regard to advice from its external advisors, Cameco’s opinion is that CRA’s position is incorrect, and Cameco intends to contest CRA’s position. However, to reflect the uncertainties of CRA’s appeals process and litigation, Cameco has decided to increase its reserve for uncertain tax positions and recognize an income tax expense of $15,000,000 in 2008 for the years 2003 through 2008. No provisions for penalties or interest have been recorded. We do not expect any cash taxes to be payable due to availability of elective deductions and tax loss carryforwards. While the resolution of this matter may result in liabilities that are higher or lower than the reserve, management believes that the ultimate resolution will not be material to Cameco’s financial position, results of operations or liquidity over the period. However, an unfavourable outcome for the years 2003 to 2008 could be material to Cameco’s financial position, results of operations or cash flows in the year(s) of resolution.

Further to Cameco’s decision to contest CRA’s 2003 reassessment, a Notice of Appeal was filed with the Tax Court of Canada on July 22, 2009.

During the third quarter of 2009, we obtained reasonable assurance that certain qualifying expenditures under investment tax credit programs would ultimately be realized and as a result, recorded a net recovery of $9,000,000 in expenses. This amount consists of recoveries related to exploration expenditures ($5,000,000), research and development costs ($4,000,000) and Cigar Lake remediation ($3,000,000), partially offset by a $3,000,000 increase in income tax expense.

Other comprehensive income (OCI) included on the consolidated statements of shareholders’ equity and the consolidated statements of comprehensive income are presented net of income taxes. The following income tax amounts are included in each component of other comprehensive income:

(thousands) Sept 30/09 Sept 30/08 Sept 30/09 Sept 30/08

Gains (losses) on derivatives designated as cash flow hedges $12,931 $23,685 $52,060 $(6,716)Gains on derivatives designated as cash flow hedges transferred to net earnings (13,525) (6,877) (35,797) (28,793) Unrealized gains (losses) on assets available-for-sale 61 (1,868) 336 (3,021) Losses on assets available-for-sale transferred to net earnings - 3,024 - 3,024

Total income tax expense (recovery) included in OCI $(533) $17,964 $16,599 $(35,506)



Accumulated other comprehensive income included on the consolidated statements of shareholders’ equity and the consolidated statement of accumulated other comprehensive income is presented net of income taxes. The following income tax amounts are included in each component of accumulated other comprehensive income:

(thousands) Sept 30/09 Sept 30/08

Gains on derivatives designated as cash flow hedges $53,003 $46,419Unrealized gains (losses) on assets available-for-sale 139 (1,149)

Total income tax expense included in AOCI $53,142 $45,270

As At

10. Per Share Amounts Three Months Ended Nine Months Ended

(thousands) Sept 30/09 Sept 30/08 Sept 30/09 Sept 30/08

Basic earnings per share computation

Net earnings $172,115 $135,451 $500,962 $419,179

Weighted average common sharesoutstanding 392,613 345,830 386,355 344,906

Basic earnings per common share $0.44 $0.39 $1.30 $1.22

Diluted earnings per share computation

Net earnings $172,115 $135,451 $500,962 $419,179

Weighted average common shares outstanding 392,613 345,830 386,355 344,906

Dilutive effect of stock options 2,120 1,471 1,872 1,945

Weighted average common sharesoutstanding, assuming dilution 394,733 347,301 388,227 346,851

Diluted earnings per common share $0.44 $0.39 $1.29 $1.21

For the quarter ended September 30, 2009, excluded from the calculation were 3,236,411 options as their exercise price was greater than the average closing market price (2008 – 894,675). For the nine months ended September 30, 2009, excluded from the calculation were 4,793,053 options whose exercise price was greater than the average closing market price (2008 – 891,375).


11. Stock Option Plan Cameco has established a stock option plan under which options to purchase common shares may be granted to officers and other employees of Cameco. The options vest over three years and expire eight years from the date granted. Options granted prior to 1999 expire 10 years from the date of the grant of the option.

The aggregate number of common shares that may be issued pursuant to the Cameco stock option plan shall not exceed 43,017,198, of which 24,396,269 shares have been issued.

On July 27, 2007, Cameco’s board of directors approved an amendment to the company’s stock option program introducing a cash settlement feature for the exercise of employee stock options. The cash settlement feature allowed option holders to elect to receive an amount in cash equal to the intrinsic value, being the excess market price of the common share over the exercise price of the option, instead of exercising the option and acquiring common shares. All outstanding stock options were subsequently classified as liabilities and carried at their intrinsic value. The intrinsic value of the liability was marked to market each period and amortized to expense over the shorter of the period to eligible retirement or the vesting period. Effective November 10, 2008, the stock option plan was amended to eliminate the alternative to settle in cash. As a result of the amendment all outstanding options are classified as equity and the fair value determined using the Black-Scholes option pricing model.

For the quarter ended September 30, 2009, Cameco has recorded compensation expense of $774,000 with an offsetting credit to contributed surplus to reflect the estimated fair value of stock options granted to employees. For the quarter ended September 30, 2008, a net recovery of $62,233,000 was recorded based on the intrinsic value of stock options granted to employees. For the nine months ended September 30, 2009, Cameco has recorded compensation expense of $4,917,000 with an offsetting credit to contributed surplus to reflect the estimated fair value of stock options granted to employees. For the nine months ended September 30, 2008, a net recovery of $42,118,000 was recorded based on the intrinsic value of stock options granted to employees.

The fair value of the options issued was determined using the Black-Scholes option-pricing model with the following assumptions:

Number of options granted 1,381,039 Average strike price $19.41Expected dividend 1.2%Expected volatility 36%Risk-free interest rate 1.6%Expected life of option 3 - 5 yearsExpected forfeitures 15%Weighted average grant date fair values $5.23

12. Goodwill Cameco tests goodwill for possible impairment on an annual basis and at any other time if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. During the third quarter of 2009, Cameco completed the goodwill impairment test for all reporting units. The results of this test have indicated there is no impairment.

13. Statements of Cash Flows Other Operating Items


Accounts receivable $(8,640) $(155,711) $216,639 $(38,006)Inventories 1,244 7,426 (48,244) (80,585) Accounts payable and accrued liabilities 14,713 (16,306) (99,838) (93,822) Other (9,588) 24,719 (78,047) 34,901

Total $(2,271) $(139,872) $(9,490) $(177,512)


14. Restructuring of the Gold Business During the first quarter of 2007, the Parliament of the Kyrgyz Republic accepted in the first reading and returned to committee for further deliberation draft legislation that, among other things, challenges the legal validity of Kumtor Gold Company’s (Kumtor) agreements with the Kyrgyz Republic, proposes recovery of additional taxes on amounts relating to past activities, and provides for the transfer of gold deposits (including Kumtor) to a state-owned entity.

On April 24, 2009, Cameco, Centerra, the Kyrgyz Government and other parties signed an agreement to resolve all the issues related to the Kumtor mine. On April 30, 2009, the Kyrgyz parliament ratified the agreement and enacted legislation authorizing implementation of the agreement. On June 11, 2009, closing occurred and Centerra issued 18,232,615 treasury shares to Kyrgyzaltyn JSC and Cameco transferred 25,300,000 shares (the Cameco Contributed Shares) of its 113,918,000 Centerra common shares to a custodian, to be held in escrow, for ultimate release to Kyrgyzaltyn JSC. The timing and number of the Cameco Contributed Shares that will be released to Kyrgyzaltyn JSC will be determined as follows:

(a) If Cameco reduces its holdings of Centerra common shares to 10.8 million or less, then the Cameco Contributed Shares will be released to Kyrgyzaltyn JSC but the number of Cameco Contributed Shares released will be subject to adjustment depending on the per share sale proceeds received by Cameco. If Cameco receives per share sale proceeds of the agreed minimum threshold or less, then 14,072,623 of the Cameco Contributed Shares will be released to Kyrgyzaltyn JSC. If Cameco receives per share sale proceeds of the agreed maximum threshold or more, then all the Cameco Contributed Shares will be released to Kyrgyzaltyn JSC. If Cameco receives per share sale proceeds between the agreed minimum and maximum thresholds, then the number of the Cameco Contributed Shares to be released to Kyrgyzaltyn JSC will be an interpolated amount.

(b) If, however, prior to Cameco reducing its holding of Centerra common shares as described above, the weighted average trading price of Centerra’s common shares exceeds the agreed maximum threshold for a period of 20 consecutive trading days, all the Cameco Contributed Shares will be released to Kyrgyzaltyn JSC after the expiration of a further 180 day period.

Cameco retains voting rights over the Cameco Contributed Shares while they are held by the custodian, and the Kyrgyz government will vote 52% of the treasury shares issued on closing as directed by Cameco until all or some of the Cameco Contributed Shares are released as set forth above. Accordingly, Cameco retains voting control over Centerra until all or some of the Cameco Contributed Shares are released.

The estimate of the loss related to this agreement is to be based on Centerra’s share price at the end of each reporting period. At September 30, 2009, the pre-tax loss was estimated to be $138,000,000 and an expense of $7,800,000 was recorded during 2009 to increase the amount provided in prior years.

As the number of the Cameco Contributed Shares ultimately transferred to Kyrgyzaltyn JSC is contingent as described above, the actual loss may be materially different than our current estimate.

15. Commitments and Contingencies The following represent the material legal claims against the company and its subsidiaries.

(a) On February 12, 2004, Cameco, Cameco Bruce Holdings II Inc., BPC Generation Infrastructure Trust and TransCanada Pipelines Limited (collectively, the “Consortium”) sent a notice of claim to British Energy Limited and British Energy International Holdings Limited (collectively, “BE”) requesting, amongst other things, indemnification for breach of a representation and warranty contained in the February 14, 2003, Amended and Restated Master Purchase Agreement (the “MPA”). The alleged breach is that the Unit 8 steam generators were not “in good condition, repair and proper working order, having regard to their use and age.” This defect was discovered during a planned outage conducted just after closing. As a result of this defect, the planned outage had to be significantly extended. The Consortium claimed damages in the amount of $64,558,200 being 79.8% of the $80,900,000 of damages actually incurred, plus an unspecified amount to take into account the reduced operating life of the steam generators. By agreement of the parties, an arbitrator has been appointed to arbitrate the claims and a schedule has been set for the next steps in the proceeding.

The Consortium served its claim on October 21, 2008, and has amended it as required, most recently on August 7, 2009. BE served its answer and counter-statement on December 22, 2008, most recently amended on July 8, 2009, and the Consortium served its reply and answer to counter-statement on January 22, 2009, most recently amended on August 7, 2009.


The Unit 8 steam generators require on-going monitoring and maintenance as a result of the defect. In addition to the $64,558,200 in damages sought in the notice of claim, the claim seeks an additional $4,900,000 spent on inspection, monitoring and maintenance of Unit 8, and $31,900,000 in costs for future monitoring and maintenance, as well as repair costs and lost revenue due to anticipated unplanned outages as a consequence of the defect in Unit 8. The initial claim had also sought damages for the early replacement of the Unit 8 steam generators due to the defect shortening their useful operating lives. However, recent inspection data and analysis of the condition of the Unit 8 steam generators now indicates that they will continue to function until the end of the Consortium's lease of the Bruce Power facility in 2018, as was expected at the time the MPA was entered into. The claim for early replacement was thus abandoned via an amendment to the claim on August 7, 2009. The parties have completed oral discoveries and are currently in the process of completing answers to undertakings given during discoveries. The hearing has been scheduled from November 30, 2009 to December 18, 2009.

In anticipation of this claim, BE issued on February 10, 2006, and then served on Ontario Power Generation Inc. (OPG) and Bruce Power LP a Statement of Claim. This Statement of Claim seeks damages for any amounts that BE is found liable to pay to the Consortium in connection with the Unit 8 steam generator arbitration described above, damages in the amount of $500,000,000, costs and pre and post judgment interest amongst other things. This action is in abeyance pending further developments on the Unit 8 steam generator arbitration.

(b) Cameco, TransCanada and BPC have assumed the obligations to provide financial guarantees on behalf of BPLP. Cameco has provided the following financial assurances, with varying terms that range from 2004 to 2018: (i) Licensing assurances to Canadian Nuclear Safety Commission of up to $133,300,000. At September 30,

2009, Cameco’s actual exposure under these assurances was $23,700,000. (ii) Guarantees to customers under power sale agreements of up to $38,300,000. Cameco did not have any

actual exposure under these agreements at September 30, 2009. (iii) Termination payments to OPG pursuant to the lease agreement of $58,300,000.

The fair value of these guarantees is nominal.

(c) Under a supply contract with the Ontario Power Authority (OPA), BPLP is entitled to receive payments from the OPA during periods when the market price for electricity in Ontario is lower than the floor price defined under the agreement during a calendar year. On July 6, 2009, BPLP and the OPA amended the supply contract such that beginning in 2009, the annual payments received will not be subject to repayment in future years. Previously, the payments received under the agreement were subject to repayment during the entire term of the contract, dependent on the spot price in future periods. The agreement remains in effect until the earlier of December 31, 2020 or one year after the shutdown of the BPLP units. During 2009, BPLP became entitled to $389,000,000 under this agreement and currently expects to repay $12,000,000. The remaining $377,000,000 was recognized as revenue with Cameco’s share being $119,000,000.

(d) On October 23, 2009, Centerra received a claim for compensation from the General Department of Specialized Inspection (SSIA) of Mongolia. The concern indicated by the SSIA is the status of certain mineral reserves, including alluvial reserves, covered by the Boroo mine licenses that are recorded in the Mongolian state reserves registry, but for which there are no or incomplete records or reports of mining activity. Centerra believes that it has properly reported all of its mining activities since it began operations in 2004. Centerra is disputing the claim and believes that the issue will be resolved through negotiation with the authorities without a material impact.


16. Segmented Information For the three months ended September 30, 2009

Fuel Inter-(thousands) Uranium Services Electricity Gold Segment Total

Revenue $328,896 $50,433 $144,823 $176,399 $(6,448) $694,103

Expenses Products and services sold 212,114 41,251 55,414 105,600 (6,646) 407,733 Depreciation, depletion and reclamation 47,979 5,473 13,547 30,480 (150) 97,329 Exploration [note 9] 10,654 - - 7,550 - 18,204 Other expense 753 3,951 - - - 4,704 Cigar Lake remediation [note 9] 2,927 - - - - 2,927 Restructuring costs [note 14] - - - 26,900 - 26,900 Loss on sale of assets 2,337 - - - - 2,337 Non-segmented expenses (85,786)

Earnings (loss) before income taxes and minority interest 52,132 (242) 75,862 5,869 348 219,755 Income tax expense [note 9] 37,638 Minority interest 10,002

Net earnings $172,115

For the three months ended September 30, 2008 Fuel Inter-

(thousands) Uranium Services Electricity Gold Segment Total

Revenue $395,815 $68,630 $127,885 $143,183 $(6,617) $728,896

Expenses Products and services sold 223,258 64,815 52,728 84,650 (13,299) 412,152 Depreciation, depletion and reclamation 52,081 7,058 11,631 18,921 (495) 89,196 Exploration 16,147 - - 5,745 - 21,892 Other expense 26,008 - - - - 26,008 Cigar Lake remediation 2,150 - - - - 2,150 Restructuring costs [note 14] - - - 2,200 - 2,200 Gain on sale of assets (129) - - - - (129) Non-segmented expenses 25,713

Earnings (loss) before income taxes and minority interest 76,300 (3,243) 63,526 31,667 7,177 149,714 Income tax expense [note 9] 6,021 Minority interest 8,242



For the nine months ended September 30, 2009 Fuel Inter-

(thousands) Uranium Services Electricity Gold Segment Total

Revenue $1,107,909 $185,619 $384,825 $426,801 $(22,074) $2,083,080

Expenses Products and services sold 637,169 132,212 184,918 315,327 (16,815) 1,252,811 Depreciation, depletion and reclamation 114,840 16,973 42,256 90,594 229 264,892 Exploration [note 9] 33,074 - - 19,433 - 52,507 Other expense 6,508 18,402 - - - 24,910 Cigar Lake remediation [note 9] 13,119 - - - - 13,119 Restructuring costs [note 14] - - - 7,800 - 7,800 Loss on sale of assets 183 - - - - 183 Non-segmented expenses (93,128)

Earnings (loss) before income taxes and minority interest 303,016 18,032 157,651 (6,353) (5,488) 559,986 Income tax expense [note 9] 77,059 Minority interest (18,035)



Fuel Inter-(thousands) Uranium Services Electricity Gold Segment Total

Revenue $1,062,315 $182,206 $319,255 $399,352 $(21,654) $1,941,474

Expenses Products and services sold 486,972 168,750 190,226 235,090 (24,664) 1,056,374 Depreciation, depletion and reclamation 102,619 19,421 33,926 47,997 (785) 203,178 Exploration 37,788 - - 15,868 - 53,656 Other expense 30,245 - - - - 30,245 Cigar Lake remediation 8,883 - - - - 8,883 Restructuring costs [note 14] - - - 8,800 - 8,800 Gain on sale of assets (3,206) - - - - (3,206) Non-segmented expenses 154,318

Earnings (loss) before income taxes and minority interest 399,014 (5,965) 95,103 91,597 3,795 429,226 Income tax recovery [note 9] (16,677) Minority interest 26,724


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