management’s discussion and analysis · 2015. 4. 23. · 2010 third quarter report 1...

Management’s discussion and analysis

for the quarter ended September 30, 2010

Third quarter update......................................................... 4

Financial results ................................................................. 8

Our operations and development projects ....................... 23

Qualified persons ............................................................. 27

Additional information....................................................... 28

Throughout this document, the terms we, us, our and Cameco mean Cameco Corporation and its subsidiaries.

2010 THIRD QUARTER REPORT 1

Management’s discussion and analysis

This management’s discussion and analysis (MD&A) includes information that will help you understand management’s perspective of our unaudited consolidated financial statements and notes for the quarter ended September 30, 2010. The information is based on what we knew as of November 5, 2010 and updates our first and second quarter MD&A and annual MD&A included in our 2009 annual report.

As you review this MD&A, we encourage you to read our unaudited consolidated financial statements and notes for the period ended September 30, 2010 as well as our audited consolidated financial statements and notes for the year ended December 31, 2009 and annual MD&A of the audited financial statements. You can find more information about Cameco, including our audited consolidated financial statements and our most recent annual information form, on our website at cameco.com, on SEDAR at sedar.com or on EDGAR at sec.gov. You should also read our annual information form before making a decision to invest in our securities.

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

About forward-looking information

Our MD&A includes statements and information about our expectations for the future. When we discuss our strategy, plans, future financial and operating performance, or other things that have not yet taken place, we are making statements considered to be forward-looking information or forward-looking statements under Canadian and United States securities laws. We refer to them in this MD&A as forward-looking information.

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

It typically includes words and phrases about the future, such as: anticipate, expect, plan, intend, predict, goal, target, project, potential, strategy and outlook (see examples on page 2).

It represents our current views, and can change significantly.

It is based on a number of material assumptions, including those we’ve listed below, which may prove to be incorrect.

Actual results and events may be significantly different from what we currently expect, due to the risks associated with our business. We list a number of these material risks below. We recommend you also review our annual information form and our annual MD&A, which include a discussion of other material risks that could cause actual results to differ significantly from our current expectations.

Forward-looking information is designed to help you understand management’s current views of our near and longer term prospects, and it may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws.

CAMECO CORPORATION 2

Examples of forward-looking information in this MD&A

production at our uranium operations from 2010 to 2014 and our target for doubling annual production by 2018

our expectations about future worldwide uranium supply and demand

our expectation that delivery patterns for uranium and fuel services will be similar to 2009, with deliveries in the fourth quarter accounting for about a third of our 2010 sales volume

our expectation that we will invest significantly in expanding production at our existing mines and advancing projects as we pursue our growth strategy

our expectation that our existing cash balances and operating cash flows will meet our anticipated requirements over the next several years without the need for any significant additional financing

our expectation that our cash balances will decline gradually as we use the funds in our business and to pursue our growth plans

the outlook for each of our operating segments for 2010, and our consolidated outlook for the year

our expectation that our plans to double annual uranium production by 2018 will not be impacted by the reduction in our 2010 planned capital expenditures

our expectation that our operating and investment activities in 2010 will not be constrained by the financial covenants in our general credit facilities

our expectation that our unit costs will rise in the fourth quarter due to receipt of additional purchased material

our uranium price sensitivity analysis our mid-2013 target for initial production from Cigar

Lake and our 2010 Cigar Lake plans the discussion of the expected impact of IFRS on

our financial statements, internal control over financial reporting and disclosure controls and procedures, our business activities in general, and our estimate of IFRS opening balances and interim period financial results

Material risks

actual sales volumes or market prices for any of our products or services are lower than we expect for any reason, including changes in market prices or loss of market share to a competitor

we are adversely affected by changes in foreign currency exchange rates, interest rates or tax rates

production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms

our estimates of production, purchases, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate

we are unable to enforce our legal rights, or are subject to litigation or arbitration that has an adverse outcome

there are defects in title to our properties our reserve and resource estimates are inaccurate,

or we face unexpected or challenging geological, hydrological or mining conditions

we are affected by environmental, safety and regulatory risks, including increased regulatory burdens or delays in Australia, Canada, Kazakhstan or the US

we cannot obtain or maintain necessary permits or approvals from government authorities

we are affected by political risks in a developing country where we operate

we are affected by terrorism, sabotage, blockades, accident or a deterioration in political support for, or demand for, nuclear energy

there are changes to government regulations or policies, including tax and trade laws and policies

our suppliers of purchased uranium and conversion fail to fulfil contract delivery commitments

delay or lack of success in remediating and developing Cigar Lake

we are affected by natural phenomena, including inclement weather, fire, flood and earthquakes

our operations are disrupted due to problems with our own or our customers’ facilities, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour relations issues, strikes or lockouts, underground floods, pitwall failure, cave-ins and other developments and operating risks

new IFRS standards or changes in the standards or their interpretation


Material assumptions

sales and purchase volumes and prices for uranium, fuel services and electricity

expected production costs expected spot prices and realized prices for

uranium, and other factors discussed on page 18, Price sensitivity analysis: uranium

tax rates, foreign currency exchange rates and interest rates

decommissioning and reclamation expenses reserve and resource estimates the geological, hydrological and other conditions at

our mines, including the accuracy of our expectations about the condition of underground workings at Cigar Lake

our Cigar Lake remediation and development plans succeed

our ability to continue to supply our products and services in the expected quantities and at the expected times

our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals in Australia, Canada, Kazakhstan or the US

our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, labour relations issues, underground floods, or other development or operating risks

our IFRS related forecasts are not significantly impacted by new IFRS standards or changes in the standards or their interpretation or changes in our policy choices


Third quarter update

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

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

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

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

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

Our performance

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

For comparison purposes, we have recast our consolidated financial results for 2008 and 2009 (presented in this document) to show the impact of Centerra as a discontinued operation, which is required under Canadian GAAP. The change affected a number of financial measures, including revenue, gross profit, administration costs and income tax expense. See note 12 to the financial statements for more information.

Third quarter

Net earnings this quarter were $98 million ($0.25 per share diluted) compared to $172 million ($0.44 per share diluted) in the third quarter of 2009. In addition to the items noted below, our net earnings were impacted by a stronger Canadian dollar. Our after-tax unrealized mark-to-market gains on financial instruments were $29 million compared to $94 million in the third quarter of 2009.

Three months ended September 30

Nine months ended September 30Highlights

($ millions except where indicated) 2010 2009 change 2010 2009 change

Revenue 419 518 (19)% 1,450 1,656 (12)%

Gross profit 152 149 2% 499 544 (8)%

Net earnings 98 172 (43)% 308 501 (39)%

$ per common share (diluted) 0.25 0.44 (43)% 0.78 1.29 (40)%

Adjusted net earnings (non-GAAP, see page 9) 80 94 (15)% 305 358 (15)%

$ per common share (adjusted and diluted) 0.20 0.24 (17)% 0.77 0.92 (16)%

Cash provided by operations (after working capital changes) (18) 175 (110)% 387 502 (23)%

Uranium $US/lb

$Cdn/lb

40.63

43.01

34.24

39.18

19%

10%

41.46

43.90

37.26

45.80

11%

(4)%

Average realized prices

Fuel services $Cdn/kgU 16.32 16.82 (3)% 18.19 19.85 (8)%

Electricity $Cdn/MWh 57.00 66.00 (14)% 58.00 64.00 (9)%


On an adjusted basis, our earnings this quarter were $80 million ($0.20 per share diluted) compared to $94 million ($0.24 per share diluted) (non-GAAP, see page 9) in the third quarter of 2009. The decline was due to:

lower profits from our electricity businesses due to lower realized prices and higher costs

higher exploration expenditures

Partially offset by:

higher profits from our uranium business due to lower costs and higher $Cdn realized selling prices

higher profits from our fuel services business due to higher sales volumes and lower costs

See Financial results by segment for more detailed discussion.

First nine months

Net earnings in the first nine months of the year were $308 million ($0.78 per share diluted) compared to $501 million ($1.29 per share diluted) in the first nine months of 2009. In addition to the items noted below, our net earnings were impacted by lower after-tax unrealized mark-to-market gains on financial instruments, $16 million compared to $147 million in 2009. While the Canadian dollar strengthened slightly in the first nine months of 2010, it strengthened to a much greater extent in the same period of 2009.

On an adjusted basis, our earnings for the first nine months of this year were $305 million ($0.77 per share diluted) compared to $358 million ($0.92 per share diluted) (non-GAAP, see page 9). The decline was due to:

lower earnings from our uranium business due to lower sales volumes and lower $Cdn realized prices. Despite an 11% increase in our $US realized uranium prices, the stronger Canadian dollar year-over-year led to a 4% decline in $Cdn realized prices. Our exchange rate averaged $1.06 compared to $1.23 a year ago.

lower profits in our electricity business due to lower realized prices

higher exploration expenditures, particularly in Australia and Kazakhstan

Partially offset by:

higher profits from our fuel services business due to higher sales volumes and lower costs


Operations update


Nine months ended September 30 Highlights

September 30 2010 2009 change 2010 2009 change

Production volume (million lbs) 5.6 5.6 - 16.5 14.1 17%

Sales volume (million lbs) 5.6 8.3 (33)% 20.5 23.9 (14)%

Uranium

Revenue ($ millions) 244 329 (26)% 912 1,108 (18)%

Production volume (million kgU) 2.3 4.1 (44)% 11.7 8.4 39%

Sales volume (million lbs) 3.9 2.8 39% 10.7 8.9 20%

Fuel services

Revenue ($ millions) 69 50 38% 208 186 12%

Output (100%) (TWh) 6.3 6.2 2% 19.3 18.2 6%

Revenue (100%) 363 458 (21)% 1,116 1,218 (8)%

Electricity

Our share of earnings before taxes ($ millions)

37 78 (53)% 115 162 (29)%

Production in our uranium segment this quarter was the same as in the third quarter of 2009 and 17% higher for the first nine months of this year.

We expect uranium production will be 22 million pounds this year compared to our previous estimate of 21.5 million pounds, with increased production at Rabbit Lake and Inkai. See Uranium – production overview for details.


As announced on November 1, 2010, unionized employees at McArthur River and Key Lake agreed to a new four-year collective agreement that expires on December 31, 2013. The new contract includes a 14.75% wage increase over the term of the agreement.

At Cigar Lake, we have decided to implement a surface freeze strategy we expect will:

shorten the ramp up period for the project by bringing forward uranium production (up to 10 million pounds) into the early years

improve mining costs and project economics

Production in our fuel services segment decreased by 44% this quarter compared to 2009 primarily due to the planned annual maintenance shutdown of the Port Hope UF6 plant, which operated throughout the third quarter of 2009. Production for the first nine months of the year increased by 39%, largely due to the routine operation of the Port Hope UF6 plant, which did not operate for most of the first half of 2009.

In our electricity segment, BPLP’s generation was 2% higher for the quarter and 6% higher for the first nine months, compared to the same periods last year. The capacity factor this quarter was 88%, and 90% for the first nine months of the year.

Uranium market update

Of note this quarter:

The United States Enrichment Corporation (USEC) sold approximately 0.6 million pounds U3O8 equivalent at the end of September. The United States Department of Energy (DOE) made the material available to USEC in return for the accelerated cleanup work at the Portsmouth gaseous diffusion plant. This was the fourth sale in 2010 and brings the total DOE material provided to the market this year to about 2.4 million pounds U3O8 equivalent.

Industry prices

1 Average of prices reported by TradeTech and Ux Consulting (Ux)

On the spot market, where purchases call for delivery within one year, the volume reported for the third quarter of 2010 was about 13.3 million pounds U3O8. This is ahead of the 11.2 million pounds purchased in the third quarter of 2009. For the first nine months of the year, spot purchases totalled 36 million pounds compared to 43.5 million pounds for the same period in 2009.

Spot uranium prices trended up during the quarter. Since the end of July, the spot price has followed a pattern of increases followed by moderate decreases. This resulted in an overall higher price as market activity picked up and sellers looked for higher prices. Demand in the spot market continues to be discretionary.

Sept 30 June 30 Mar 31 Sept 30 June 30 Mar 31 2010 2010 2010 2009 2009 2009

Uranium ($US/lb U3O8) 1

Average spot market price

Average long-term price

46.63

61.00

41.75

59.00

41.88

59.00

42.88

64.50

51.50

65.00

42.00

69.50

Fuel services ($US/kgU UF6)

1

Average spot market price

North America

Europe

Average long-term price

North America

Europe

Note: the industry does not publish UO2 prices.

13.00

12.50

13.13

13.50

7.00

7.88

11.25

12.75

5.63

7.50

11.00

12.75

6.25

8.25

11.75

13.13

7.00

8.50

12.25

13.38

8.50

9.75

12.25

13.38

Electricity ($/MWh)

Average Ontario electricity spot price

43.00

34.00

34.00

22.00

23.00

43.00


Long-term uranium prices rose to $61.00 (US) per pound during the quarter. Long-term contracts usually call for deliveries to begin more than two years after the contract is finalized, and use a number of pricing formulas, including fixed prices adjusted by inflation indices, and market referenced prices (spot and long-term indicators).

Utilities are well covered under existing contracts and have been building inventory levels of U3O8 since 2004. We expect uranium demand in the near term to be somewhat discretionary.

Spot market UF6 conversion prices increased significantly this quarter. The increase is being attributed to the loss of production caused by a labour dispute at a uranium conversion facility in the US. Long-term UF6 conversion prices also increased this quarter due to increased demand for UF6 conversion.

Long-term fundamentals are strong

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

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

Shares and stock options outstanding At November 5, 2010, we had:

393,493,749 common shares and one Class B share outstanding

8,474,864 stock options outstanding, with exercise prices ranging from $5.75 to $55.00

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


Financial results

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

Consolidated financial results

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

For comparison purposes, we have recast our consolidated financial results for 2008 and 2009 (presented in this document) to show the impact of Centerra as a discontinued operation, which is required under Canadian GAAP. The change affected a number of financial measures, including revenue, gross profit, administration costs and income tax expense. See note 12 to the financial statements for more information.



($ millions except per share amounts) 2010 2009 change 2010 2009 change

Revenue 419 518 (19)% 1,450 1,656 (12)%

Net earnings 98 172 (43)% 308 501 (39)%

$ per common share (basic) 0.25 0.44 (43)% 0.78 1.30 (40)%

$ per common share (diluted) 0.25 0.44 (43)% 0.78 1.29 (40)%

Adjusted net earnings (non-GAAP, see page 9) 80 94 (15)% 305 358 (15)%

$ per common share (adjusted and diluted) 0.20 0.24 (17)% 0.77 0.92 (16)%

Cash provided by operations (after working capital changes) (18) 175 (110)% 387 502 (23)%

Net earnings

Net earnings this quarter were $98 million ($0.25 per share diluted) compared to $172 million ($0.44 per share diluted) in the third quarter of 2009 due to:

lower after-tax unrealized mark-to-market gains on financial instruments, $29 million compared to $94 million in the third quarter of 2009 due to a stronger Canadian dollar

lower earnings from our electricity business due to a decline in realized prices and higher costs

higher exploration expenditures

2010 Q3 results

Consolidated financial results ........................... 8

Outlook for 2010................................................ 14

Liquidity and capital resources .......................... 15

Financial results by segment ............................ 17

Uranium............................................................. 17

Fuel services .................................................... 20

Electricity........................................................... 21


Net earnings in the first nine months of the year were $308 million ($0.78 per share diluted) compared to $501 million ($1.29 per share diluted) in the first nine months of 2009 due to:

lower after-tax unrealized mark-to-market gains on financial instruments, $16 million compared to $147 million in 2009. While the Canadian dollar strengthened slightly in the first nine months of 2010, it strengthened to a much greater extent in the same period of 2009.

lower earnings from our uranium business due to lower sales volumes and lower $Cdn realized prices. Despite a 11% increase in our $US realized uranium prices, the stronger Canadian dollar year-over-year led to a 4% decline in $Cdn realized prices. Our exchange rate averaged $1.06 compared to $1.23 a year ago.

lower earnings from our electricity business due to a decline in realized prices

higher exploration expenditures, particularly in Australia and Kazakhstan

Adjusted net earnings (non-GAAP measure)

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

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

Three months endedSeptember 30

Nine months endedSeptember 30

($ millions) 2010 2009 2010 2009

Net earnings (GAAP measure) 98 172 308 501

Adjustments (after tax)

Losses from discontinued operations - 23 - 42

Unrealized gains on financial instruments (18) (101) (3) (185)

Adjusted net earnings (non-GAAP measure) 80 94 305 358


The tables that follow describe what contributed to the changes in adjusted net earnings and revenue this quarter and for the first nine months of the year.

Change in adjusted net earnings ($ millions)


Nine months ended September 30

Adjusted net earnings – 2009 94 358

Change in gross profit by segment (we calculate gross profit by deducting from revenue the cost of products and services sold, and depreciation, depletion and reclamation (DDR))

Lower sales volumes

Higher (lower) realized prices ($Cdn)

Lower costs

(23)

21

34

(51)

(39)

56

Uranium

change - uranium 32 (34)

Higher sales volumes

Lower realized prices ($Cdn)

Lower costs

2

(2)

5

8

(18)

23

Fuel services

change – fuel services 5 13

Higher sales volumes

Lower realized prices ($Cdn)

Lower (higher) costs

2

(33)

(3)

10

(56)

13

Electricity

change – electricity (34) (33)

Other changes

Exploration expense

Realized gains on derivatives & foreign exchange

Reduced losses from associated companies

Income taxes

Miscellaneous

(25)

24

-

(10)

(6)

(35)

45

14

(32)

9

Adjusted net earnings - 2010 80 305

Revenue

Change in revenue

($ millions) Three months ended

September 30 Nine months ended

September 30

Revenue - 2009 518 1,656

Uranium

Lower sales volumes (106) (157)

Higher (lower) realized prices ($Cdn) 21 (39)

Fuel services

Higher sales volumes 18 40

Lower realized prices ($Cdn) (2) (18)

Electricity

Higher sales volumes 2 20

Lower realized prices ($Cdn) (32) (52)

Revenue – 2010 419 1,450



Average realized prices



2010 2009 change 2010 2009 change

Uranium $US/lb

$Cdn/lb

40.63

43.01

34.24

39.18

19%

10%

41.46

43.90

37.26

45.80

11%

(4)%

Fuel services $Cdn/kgU 16.32 16.82 (3)% 18.19 19.85 (8)%

Electricity $Cdn/MWh 57.00 66.00 (14)% 58.00 64.00 (9)%

Our customers choose when in the year to receive deliveries of uranium and fuel services products, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly. We expect the trend in delivery patterns in 2010 to be similar to 2009, with deliveries in the fourth quarter accounting for about a third of our 2010 sales volume.

Quarterly trends

Highlights ($ millions except per share amounts)

2010 2009 2008

Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4

Revenue 419 546 485 659 518 646 493 640

Net earnings 98 68 142 598 172 247 82 31

$ per common share (basic) 0.25 0.17 0.36 1.52 0.44 0.63 0.22 0.08

$ per common share (diluted) 0.25 0.17 0.36 1.52 0.44 0.63 0.22 0.08

Adjusted net earnings (non-GAAP, see page 9) 80 114 111 169 94 162 103 179

$ per share diluted 0.20 0.29 0.28 0.43 0.24 0.41 0.27 0.49

Earnings from continuing operations 98 68 142 174 195 269 78 5

$ per common share (basic) 0.25 0.17 0.36 0.44 0.49 0.69 0.21 0.01

$ per common share (diluted) 0.25 0.17 0.36 0.44 0.49 0.69 0.21 0.01

Cash provided by operations (18) 272 133 188 175 147 180 224

Key things to note:

Our financial results are strongly influenced by the performance of our uranium segment, which accounted for 58% of consolidated revenues in the third quarter of 2010.

The timing of customer requirements, which tend to vary from quarter to quarter, drives revenue in the uranium and fuel services segments.

Net earnings do not trend directly with revenue due to unusual items and transactions that occur from time to time. We use adjusted net earnings, a non-GAAP measure, as a more meaningful way to compare our results from period to period (see page 9 for more information).

Cash from operations tends to fluctuate as a result of the timing of deliveries and product purchases in our uranium and fuel services segments.

Quarterly results are not necessarily a good indication of annual results due to the variability in customer requirements noted above.


Administration

($ millions) Three months ended

September 30 Nine months ended

September 30

2010 2009 2010 2009

Direct administration 35 31 94 83

Stock-based compensation 5 2 7 11

Total administration 40 33 101 94

Direct administration costs were $35 million this quarter, or $4 million higher than the same period last year. Through the first nine months of 2010, our direct administration costs were 13% higher than in 2009. These increases are in line with our previous guidance and reflect the costs necessary for evaluating and pursuing growth opportunities including:

increased hiring

studies and analysis of various opportunities

Exploration

Uranium exploration expenses were $35 million this quarter compared to $11 million in the same quarter in 2009, as activity in Canada, Kazakhstan and at the Kintyre project in Australia increased. Exploration expenses in the first nine months of the year increased to $68 million from $33 million in 2009. Exploration in 2010 is focused on Canada, the United States, Mongolia, Kazakhstan, Australia and South America.

Gains and losses on derivatives

We recorded $39 million in mark-to-market gains on our financial instruments this quarter, compared to gains of $129 million in the third quarter of 2009. In the first nine months of the year, we recorded $22 million in mark-to-market gains on our financial instruments compared to $201 million in 2009. While the Canadian dollar strengthened slightly in the first nine months of 2010, it strengthened significantly in the first nine months of 2009.

Income taxes

In the third quarter of 2010, we recorded an income tax expense of $8 million compared to $28 million in the third quarter of 2009. The decline this quarter was mainly due to a $121 million decrease in pretax earnings, which was largely attributable to the decline in gains we recorded on derivatives compared to 2009.

On an adjusted basis, we recorded an income tax expense of $1 million this quarter compared to a net recovery of $9 million in the third quarter of 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 accordingly, we began to recognize the expected benefits in our financial results.

Our effective tax rate in this quarter on an adjusted net earnings basis was 1% compared to a recovery of 11% for the third quarter of 2009.

In the first nine months of 2010, we recorded an income tax expense of $15 million compared to $50 million in 2009. The decline in 2010 was mainly due to a $276 million decrease in pretax earnings, which was largely attributable to the decline in gains we recorded on derivatives compared to 2009. Lower earnings from the uranium and electricity businesses also contributed to the decline in income tax expense.

On an adjusted basis, we recorded a net income tax expense of $13 million in the first nine months of 2010 compared to a net recovery of $18 million in 2009. The increase in expense this year was mainly due to a change in the distribution of our taxable income. We earned a higher proportion of taxable income in jurisdictions with higher tax rates in the first nine months of this year.

Our effective tax rate on an adjusted earnings basis was 4% compared to a recovery of 5% in 2009.


Foreign exchange

At September 30, 2010:

The value of the US dollar relative to the Canadian dollar was $1.00 (US) for $1.03 (Cdn), down from $1.00 (US) for $1.06 (Cdn) at June 30, 2010. The exchange rate averaged $1.00 (US) for $1.04 (Cdn) over the quarter.

We had foreign currency contracts of $1.6 billion (US) and EUR 98 million at September 30, 2010. The US currency contracts had an average exchange rate of $1.00 (US) for $1.04 (Cdn).

The mark-to-market gain on all foreign exchange contracts was $4 million compared to a $26 million loss at June 30, 2010. We received cash of $7 million this quarter and $86 million for the first nine months of the year related to the settlement of foreign exchange contracts.

Sensitivity analysis

At September 30, 2010, every one-cent change in the value of the Canadian dollar versus the US dollar would change our net earnings by about $12 million (Cdn). This sensitivity is based on an exchange rate of $1.00 (US) for $1.03 (Cdn).


Outlook for 2010

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

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

Our outlook for 2010 reflects the growth expenditures necessary to help us achieve our strategy. Our outlook for uranium production, fuel services production, consolidated capital expenditures and capital expenditures for electricity has changed from the outlook in our second quarter MD&A. We explain the material changes below. All other items in the table are unchanged. We do not provide outlook for the items in the table that are marked with a dash.

See Financial results by segment for details.

Consolidated Uranium Fuel services Electricity

Production - 22 million lbs 15 to 16 million kgU -

Sales volume - 30 million lbs Increase 15% to 20% -

Capacity factor - - - About 90%

Revenue compared to 2009

Decrease 5% to 10%

Decrease 10% to 15%1

Increase 5% to 10%

Decrease 5% to 10%

Unit cost of product sold (including DDR)

- Decrease 5% to 10%2

- Increase less than 5%

Direct administration costs compared to 20093

Increase 20% to 25%

- - -

Exploration costs compared to 2009

- Increase 90% to 100%

- -

Tax rate Less than 5% - - -

Capital expenditures $475 million4 - - $36 million

1 Based on a uranium spot price of $53.50 (US) per pound (the Ux spot price as of November 1, 2010) and an exchange rate of $1.00 (US) for $1.01 (Cdn).

2 Assumes the unit cost of sale for produced material will decline by 5% to 10% relative to 2009 and the unit cost of sale for purchased material will decline by 10% to 15%.

3 Direct administration costs do not include stock-based compensation expenses. 4 Does not include our share of capital expenditures at BPLP.

We expect uranium production to be 22 million pounds this year, compared to our previous estimate of 21.5 million pounds, with increased production at Rabbit Lake and Inkai. See Uranium 2010 Q3 Updates – Operating properties for details.

We expect capital expenditures to be about $475 million in 2010, compared to our previous estimate of $510 million due to changes in the scheduling of some projects. We do not expect this reduction in capital expenditures in 2010 will impact our plans to double annual uranium production by 2018.


Sensitivity analysis

For the rest of 2010:

a change of $5 (US) from the Ux spot price on November 1, 2010 ($53.50 (US) per pound) would change revenue by $13 million and net earnings by $10 million

a change of $1 in the electricity spot price would change our 2010 net earnings by $1 million, based on the assumption that the spot price will remain below the floor price provided for under BPLP’s agreement with the Ontario Power Authority (OPA)

Liquidity and capital resources

Cash from operations

Cash from operations was $193 million lower this quarter than in 2009 due to much higher working capital requirements. Working capital changes required $142 million, primarily from an increase in accounts receivable and uranium inventories during the quarter. In 2009, working capital consumed $23 million in cash largely due to increases in accounts receivable and product inventories. Not including working capital requirements, our operating cash flows this quarter were down by $74 million, largely due to lower uranium sales volumes and a lower realized price for electricity. See Financial results by segment for details.

Cash from operations was $115 million lower for the first nine months of 2010 than for the same period in 2009 mainly due to higher working capital requirements relating to increased inventory levels and a reduction in accounts payable. Not including working capital requirements, our operating cash flows in the first nine months of this year were down by $12 million.

Debt

We use debt to provide additional liquidity. We have sufficient borrowing capacity with unsecured lines of credit totalling about $1.2 billion at September 30, 2010, compared to $1.1 billion at June 30, 2010. Our short-term borrowing and letters of credit facilities increased by about $19 million this quarter. At September 30, 2010, we had approximately $548 million outstanding in letters of credit.

Credit ratings

Third-party ratings for our commercial paper and senior debt as of September 30, 2010:

Security DBRS S&P

Commercial paper R-1 (low) A-1 (low)1

Senior unsecured debentures A (low) BBB+

1 Canadian National Scale Rating. The Global Scale Rating is A-2.

Debt covenants

We are bound by certain covenants in our general credit facilities. The financially related covenants place restrictions on total debt, including guarantees, and set minimum levels of net worth. As at September 30, 2010, we met these financial covenants and do not expect our operating and investment activities in 2010 to be constrained by them.


Long-term contractual obligations and off-balance sheet arrangements

We had two kinds of off-balance sheet arrangements at September 30, 2010:

purchase commitments

financial assurances

There have been no material changes to our long-term contractual obligations, purchase commitments and financial assurances since December 31, 2009, including payments due for the next five years and thereafter. Our long-term contractual obligations do not include our sales commitments. Please see our annual MD&A for more information.

Balance sheet

($ millions except per share amounts) Sept 30, 2010 Dec 31, 2009 change

Cash and short-term investments 1,270 1,304 (3)%

Total debt 1,032 1,041 (1)%

Inventory 514 453 13%

Total cash and short-term investments at September 30, 2010 were $1,270 million, or 3% lower than at December 31, 2009, exceeding our total debt by $238 million.

Total debt declined by $9 million to $1,032 million at September 30, 2010. Of this total, $88 million was classified as current, unchanged compared to December 31, 2009. See notes 10 and 11 of our audited annual financial statements for more detail.

Total product inventories increased by 13% to $514 million. This is the result of higher uranium inventory, as sales were lower than production and purchases in the first nine months of the year.


Financial results by segment

Uranium



Highlights 2010 2009 change 2010 2009 change

Production volume (million lbs) 5.6 5.6 - 16.5 14.1 17%

Sales volume (million lbs) 5.6 8.3 (33)% 20.5 23.9 (14)%

Average spot price ($US/lb)

Average realized price ($US/lb) ($Cdn/lb)

45.83

40.63

43.01

45.29

34.24

39.18

1%

19%

10%

43.01

41.46

43.90

46.10

37.26

45.80

(7)%

11%

(4)%

Average unit cost of sales ($Cdn/lb U3O8) (including DDR) 24.36 30.67 (21)% 27.74 30.72 (10)%

Revenue ($ millions) 244 329 (26)% 912 1,108 (18)%

Gross profit ($ millions) 101 69 46% 322 356 (10)%

Gross profit (%) 41 21 95% 35 32 9%

Third quarter

Production volumes this quarter were the same as in the third quarter in 2009.

Uranium revenues this quarter were down 26% compared to 2009, due to a 33% decline in sales volumes.

Our realized prices this quarter were higher than the third quarter of 2009 mainly due to higher prices under fixed-price sales contracts.

Total cash cost of sales (excluding DDR) decreased by 53% this quarter, to $100 million ($17.55 per pound U3O8). This was mainly the result of the following:

the 33% decline in sales volume

average unit costs for produced uranium were 31% lower

average unit costs for purchased uranium were 29% lower due to fewer purchases at spot prices

royalty charges were lower due to lower deliveries of produced material

The net effect was a $32 million increase in gross profit for the quarter.

Our average unit cost of sales for uranium was much lower in the third quarter than in the first six months of 2010. We expect that the average unit cost will rise in the fourth quarter due to receipt of additional purchased material. Our average unit cost reflects purchases once the material is received. We calculate our total cost of sales based on the average cost of all purchased and produced uranium.

First nine months

Production volumes for the first nine months of the year were 17% higher than in the previous year due to higher production at almost all our sites. See Operating properties for more information.

For the first nine months of 2010, uranium revenues were down 18% compared to 2009, due to a 14% decline in sales volumes and a 4% decrease in our $Cdn realized price. Our exchange rate averaged $1.06 compared to $1.23 a year ago. In $US, our realized price was 11% higher than in 2009 mainly due to the mix of contracts into which we delivered uranium. So far this year, deliveries have been more heavily weighted toward market related contracts, which yielded higher prices than our fixed price contracts.


Total cash cost of sales (excluding DDR) decreased by 27% in the first nine months of the year, to $466 million ($22.45 per pound U3O8). This was mainly the result of the following:

average unit costs for produced uranium were 13% lower due to higher production levels

average unit costs for purchased uranium were 19% lower due to fewer purchases at spot prices

sales volumes were 14% lower

lower royalty charges

The net effect was a $34 million decrease in gross profit for the first nine months.

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

Unit cash cost of sale ($Cdn/lb U3O8)

Quantity sold (million lbs) Three months ended

September 30 2010 2009 change 2010 2009 change

Produced 17.85 25.85 (8.00) 3.5 6.2 (2.7)

Purchased 17.05 23.87 (6.82) 2.1 2.1 -

Total 17.55 25.36 (7.81) 5.6 8.3 (2.7)

Nine months ended September 30 2010 2009 change 2010 2009 change

Produced 22.54 25.84 (3.30) 14.5 15.8 (1.3)

Purchased 22.22 27.50 (5.28) 6.0 8.1 (2.1)

Total 22.45 26.39 (3.94) 20.5 23.9 (3.4)

Price sensitivity analysis: uranium

The table below is not a forecast of prices we expect to receive. The prices we actually realize will be different from the prices shown in the table.

The table has been updated to reflect deliveries made and contracts entered into up to September 30, 2010. It is designed to indicate how the portfolio of long-term contracts we had in place on September 30, 2010 would respond to different spot prices. In other words, we would realize these prices only if the contract portfolio remained the same as it was on September 30, 2010, and none of the assumptions listed on the following page change.

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

($US/lb U3O8)

Spot prices $20 $40 $60 $80 $100 $120 $140

2010 41 42 44 46 48 51 53

2011 34 39 47 53 61 68 75

2012 35 38 47 56 65 73 82

2013 42 45 54 64 74 84 92

2014 43 46 56 65 75 85 93

The table illustrates the mix of long-term contracts in our September 30, 2010 portfolio, and is consistent with our contracting strategy.

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


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

Sales

sales volume of 30 million pounds in 2010 and every year following

Deliveries

customers take the maximum quantity allowed under each contract (unless they have already provided a delivery notice indicating they will take less)

we defer a portion of deliveries under existing contracts for 2011 and 2012

Prices

the average long-term price indicator is the same as the average spot price for the entire year (a simplified approach for this purpose only)

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

Inflation

is 2.0% per year


Fuel services

(includes results for UF6, UO2 and fuel fabrication)



Highlights 2010 2009 change 2010 2009

change

Production volume (million kgU) 2.3 4.1 (44)% 11.7 8.4 39%

Sales volume (million kgU) 3.9 2.8 39% 10.7 8.9 20%

Realized price ($Cdn/kgU) 16.32 16.82 (3)% 18.19 19.85 (8)%

Average unit cost of sales ($Cdn/kgU) (including DDR) 13.84 15.43 (10)% 13.70 15.86 (14)%

Revenue ($ millions) 69 50 38% 208 186 12%

Gross profit ($ millions) 9 4 125% 49 36 36%

Gross profit (%) 13 7 86% 24 20 20%

Third quarter

Total revenue increased by 38% due to a 39% increase in sales volumes.

Our $Cdn realized price for UF6 was affected by a less favourable exchange rate. Our exchange rate averaged $1.06 in the third quarter compared to $1.14 in 2009.

The total cost of products and services sold (including DDR) increased by 28% ($60 million compared to $47 million in the third quarter of 2009) due to the increase in sales volume. The average unit cost of sales was 10% lower due largely to lower costs for purchased material.

The net effect was a $5 million increase in gross profit.

First nine months

In the first nine months of the year, total revenue increased by 12% due to a 20% increase in sales volumes.

Our $Cdn realized price for UF6 was affected by a less favourable exchange rate. Our exchange rate averaged $1.06 compared to $1.23 last year at this time.

The total cost of products and services sold (including DDR) increased by 7% ($159 million compared to $149 million in 2009) as the impact of the increase in sales volume was largely offset by a lower cost per unit sold. The average unit cost of sales was 14% lower as we allocated costs related to the UF6 plant to inventory during the first nine months of this year. In 2009, we expensed the majority of these costs, due to the plant having been shut down throughout most of the first half.

The net effect was a $13 million increase in gross profit.


Electricity

BPLP

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




Output - terawatt hours (TWh) 6.3 6.2 2% 19.3 18.2 6%

Capacity factor (the amount of electricity the plants actually produced for sale as a percentage of the amount they were capable of producing)

88 86 2% 90 86 5%

Realized price ($/MWh) 57 66 (14)% 58 64 (9)%

Average Ontario electricity spot price ($/MWh) 43 22 95% 38 29 31%

Revenue 363 458 (21)% 1,116 1,218 (8)%

Operating costs (net of cost recoveries) 224 210 7% 709 687 3%

Cash costs

Non-cash costs

187

37

176

34

6%

9%

601

108

587

100

2%

8%

Income before interest and finance charges 139 248 (44)% 407 531 (23)%

Interest and finance charges 16 (4) n/a 30 3 n/a

Cash from operations 130 206 (37)% 497 525 (5)%

Capital expenditures 24 34 (29)% 72 83 (13)%

Distributions 100 120 (17)% 405 390 4%

Operating costs ($/MWh) 36 30 20% 37 36 3%

Our earnings from BPLP




BPLP’s earnings before taxes (100%) 123 252 (51)% 377 528 (29)%

Cameco’s share of pretax earnings before adjustments (31.6%)

39 80 (51)% 119 167 (29)%

Proprietary adjustments (2) (2) - (4) (5) 20%

Earnings before taxes from BPLP 37 78 (53)% 115 162 (29)%

Third quarter

Total electricity revenue decreased 21% this quarter compared to the third quarter of 2009 as higher output was more than offset by lower realized prices. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA, and financial contract revenue. BPLP recognized revenue of $41 million this quarter under its agreement with the OPA, compared to $205 million in the third quarter of 2009. The equivalent of about 46% of BPLP’s output was sold under financial contracts this quarter, compared to 51% in the third quarter of 2009.

The capacity factor was 88% this quarter, up from 86% in the third quarter of 2009 due to fewer planned and unplanned outage days. Operating costs were $224 million compared to $210 million in 2009.

The result was a 53% decrease in our share of earnings before taxes.

BPLP distributed $100 million to the partners in the third quarter. Our share was $32 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.


First nine months

Total electricity revenue for the first nine months of the year decreased 8% compared to 2009, as higher output was more than offset by lower realized prices. BPLP recognized revenue of $224 million under its agreement with the OPA in the first nine months of 2010, compared to $377 million for the same period in 2009. The equivalent of about 41% of BPLP’s output was sold under financial contracts in the first nine months of this year, compared to 58% in 2009.

The capacity factor was 90% for the first nine months of this year, up from 86% in 2009 due to fewer planned and unplanned outage days. Operating costs were $709 million compared to $687 million in 2009.

The result was a 29% decrease in our share of earnings before taxes.

BPLP distributed $405 million to the partners in the nine months of this year. Our share was $128 million.


Our operations and development projects

Uranium – production overview

Production this quarter was the same as in the third quarter of 2009 and 17% higher for the first nine months of the year.

Uranium production


Nine months ended September 30Cameco’s share

(million lbs U3O8) 2010 2009 change 2010 2009 change

McArthur River/Key Lake 3.7 3.8 (3)% 9.9 9.3 6%

Rabbit Lake 0.5 0.9 (44)% 2.5 2.4 4%

Smith Ranch-Highland 0.4 0.4 - 1.4 1.3 8%

Crow Butte 0.2 0.2 - 0.6 0.6 -

Inkai 0.8 0.3 167% 2.1 0.5 320%

Total 5.6 5.6 - 16.5 14.1 17%

See Uranium 2010 Q3 updates – Operating properties for details.

Outlook

Our sources of production are diversified both geographically and geologically. As outlined below, we expect production to total 116 million pounds of U3O8 over the next five years. Our strategy is to double our annual production to 40 million pounds by 2018, which we expect will come from our operating properties, development projects and other projects already in our portfolio.

Cameco’s share of production — annual forecast to 2014

Current forecast (million lbs U3O8) 2010 2011 2012 2013 2014

McArthur River/Key Lake 13.1 13.1 13.1 13.1 13.1

Rabbit Lake 3.7 3.6 3.6 3.6 3.0

US ISR 2.5 2.5 3.1 3.1 3.7

Inkai 2.7 3.1 3.1 3.1 3.1

Cigar Lake - - - 1.0 2.0

Total 22.0 22.3 22.9 23.9 24.9

Inkai requires government approval and the support of our partner, Kazatomprom, in order to produce at the forecast annual rate of 5.2 million pounds of U3O8 (our share 3.1 million pounds). We believe that it is reasonably likely that Inkai will receive these confirmations.


________________________

This forecast is forward-looking information. It is based on the assumptions and subject to the material risks discussed on page 2, and specifically on the assumptions and risks listed here. Actual production may be significantly different from this forecast.

Assumptions

we achieve our forecast production for each operation, which requires, among other things, that our mining plans succeed, Cigar Lake remediation and development plans succeed, processing plants function and our mineral reserve estimates are accurate

we obtain or maintain the necessary permits and approvals from government authorities

our production is not disrupted or reduced as a result of natural phenomena, labour disputes, political risks, shortage or lack of supplies critical to production, equipment failures or other development and operation risks

Material risks that could cause actual results to differ materially

we do not achieve forecast production levels for each operation due to a change in our mining plans, delay or lack of success in remediating and developing Cigar Lake, processing plant availability, lack of tailings capacity or for other reasons

we cannot obtain or maintain necessary permits or government approvals

natural phenomena, labour disputes, political risks, shortage or lack of supplies critical to production, equipment failures or other development and operation risks disrupt or reduce our production


Uranium 2010 Q3 updates

Operating properties

McArthur River/Key Lake

Production update

Production increased for the first nine months of the year largely as a result of a shorter maintenance shut-down and improved startup at the Key Lake mill in the second quarter compared to 2009 and strong ore supply from McArthur River. We are beginning to see the benefits from our focus on reliability and maintenance over the last few years.

Operations update

At Key Lake, the mill continues to operate well.

Construction is on schedule for the acid and oxygen plants. We finished installing structural steel and plan to winterize the buildings in the fourth quarter. We installed all major equipment in the acid plant and are in the process of installing mechanical piping.

We received regulatory approval for development of a second raisebore chamber in zone 2, panel 5 and an extraction chamber in the lower mining area of zone 4. We continue to expect first production from the lower mining area of zone 4 in 2010.

As announced on November 1, 2010, unionized employees at McArthur River and Key Lake agreed to a new four-year collective agreement that expires on December 31, 2013. The new contract includes a 14.75% wage increase over the term of the agreement.

Rabbit Lake

Production update

Production this quarter was 44% below the same quarter in 2009. As planned, the mill operated for a shorter period than in the third quarter of 2009 resulting in lower production. Production in the first nine months was slightly higher than last year. We expect to see large variations in mill production from quarter to quarter as we manage ore supply to ensure efficient operation of the mill. We expect production for the year will be 3% higher than our previous estimate of 3.6 million pounds.

Operations update

We completed the scheduled mill maintenance shutdown this quarter, and the mill returned to normal operations on September 1, 2010. We repaired and replaced equipment and infrastructure throughout the mill. At the Eagle Point mine, we installed and commissioned a new exhaust air raise, which will support future activities in the northern part of the mine.


Smith Ranch-Highland and Crow Butte

Production update

Production remains on schedule.

Operations update

At Smith Ranch-Highland, we no longer expect regulatory approval for the Reynolds Ranch expansion in the second half of 2010. The regulators have indicated they have a large volume of permits to process, therefore approval of our expansion is not expected to occur until late in 2011. We do not expect this delay to impact production.

Inkai

Production update

Completion of the processing facilities and a stable acid supply resulted in higher production for both the quarter and first nine months of the year compared to the same periods in 2009.

We have increased our 2010 production forecast by 17%, from our previous estimate of 2.3 million pounds. The increase reflects strong wellfield performance in the first nine months of the year and 2009 uranium inventories at Inkai being processed this year.

Operations update

In mid-June Inkai received approval in principle to increase annual production from blocks 1 and 2 to 3.9 million pounds U3O8 (100% basis), which is in line with Inkai’s production target for 2010. An amendment to the subsoil use contract to implement this is progressing through the Kazakh government approval process.

We continue to work with Kazatomprom to evaluate opportunities aimed at cooperating on UF6 conversion.

Development project

Cigar Lake

This quarter we:

substantially completed clean up, inspection, assessment and securing of the underground development areas

completed freeze drilling and outfitting of the freeze holes at shaft 2, as part of our preparations to resume shaft sinking

progressed remediation of the underground brine handling system to support freezing of the orebody and shaft 2

increased pumping capacity to 2,500 m3/hr

began backfilling of the 465 metre level Our activities for the remainder of 2010 will focus on carrying out our plans and implementing the strategies we have identified to move Cigar Lake towards production. Our plans include:

continuing to restore the underground mine systems, infrastructure and underground development areas so we can resume construction

working to obtain regulatory approval of the environmental assessment that will allow the release of treated water directly to Seru Bay of Waterbury Lake

beginning to freeze the ground around shaft 2 in preparation to resume shaft sinking

implementing a surface freeze strategy we expect will shorten the ramp up period for the project by bringing forward uranium production (up to 10 million pounds) into the early years and improve mining costs and project economics

continuing the surface drilling program designed to upgrade mineral resources


We continue to target initial production in mid-2013.

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

Projects under evaluation

We continue to advance the Kintyre and Millennium projects toward development decisions.

Fuel services 2010 Q3 updates

Port Hope conversion services Cameco Fuel Manufacturing Inc. (CFM) Springfields Fuels Ltd. (SFL)

Fuel services production totalled 2.3 million kgU this quarter, compared to 4.1 million kgU in the third quarter of 2009. Lower production was primarily due to the planned annual maintenance shutdown of the Port Hope UF6 plant, which operated throughout the third quarter of 2009.

Production for the first nine months of the year was 11.7 million kgU compared to 8.4 million kgU in the first nine months of 2009. Higher production is largely due to the routine operation of the Port Hope UF6 plant, which did not operate for most of the first half of 2009.

Qualified persons

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

McArthur River/Key Lake

David Bronkhorst, vice-president, Saskatchewan mining south, Cameco

Les Yesnik, general manager, Key Lake, Cameco

Inkai

Charles Foldenauer, general manager operations and development, Inkai

Cigar Lake

Grant Goddard, vice-president, Saskatchewan mining north, Cameco


Additional information

Related party transactions

We buy significant amounts of goods and services for our Saskatchewan mining operations from northern Saskatchewan suppliers to support economic development in the region. One of these suppliers is Points Athabasca Contracting Ltd. (PACL). In the first nine months of 2010, we paid PACL $19.0 million for construction and contracting services (2009 - $21.6 million). These transactions were carried out in the normal course of business. A member of Cameco’s board of directors is the president of PACL.

Controls and procedures

As of September 30, 2010, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Based upon that evaluation and as of September 30, 2010, the Chief Executive Officer and Chief Financial Officer concluded that the disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under applicable securities laws is recorded, processed, summarized and reported as and when required, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting during the quarter ended September 30, 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

New accounting pronouncements

International financial reporting standards (IFRS)

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

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

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

Phase 1: Preliminary study and diagnostic — complete

During this phase, we:

completed a high-level impact assessment

prioritized areas to evaluate in phase 2

developed a detailed plan for convergence and implementation

determined which information technology systems need to be modified to meet IFRS reporting requirements. We tested and implemented systems modifications by June 30, 2009.


Phase 2: Detailed component evaluation — complete

During this phase, we:

assessed the impact of the adoption of IFRS on our results of operations, financial position and financial statement disclosures

developed a detailed, systematic gap analysis of accounting and disclosure differences between Canadian GAAP and IFRS, which will help us make final decisions about accounting policies and our overall conversion strategy

specified all changes we needed to make to existing business processes

Phase 3: Embedding – in progress

During this final phase, we will:

carry out the changes to our business processes

receive the audit committee’s approval of our accounting policy changes

complete the training process for our audit committee, board members and staff

communicate the impact of the IFRS transition to external stakeholders

collect the financial information we need to create our 2010 and 2011 financial statements under IFRS

receive the board’s approval of the new statements

Progress update

During the quarter, we continued to evaluate key accounting policy alternatives and implementation decisions, but have not yet fully completed our analysis of all accounting effects of adopting IFRS. We have quantified the majority of items in our January 1, 2010 opening balances and earnings for the three month periods ended March 31, 2010 and June 30, 2010 under IFRS subject to changes in IFRS standards or their interpretation. See Opening balances and interim period financial results under IFRS for more information about the most significant differences expected between our Canadian GAAP and IFRS balances.

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

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

Asset impairment

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

We compare the carrying value of the asset with undiscounted future cash flows to see whether there is an impairment.

If there is an impairment, we measure it by comparing the carrying value of the asset with its fair value.

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

Compare the carrying value of the asset with the higher of its fair value less costs to sell or its value in use.

The difference in accounting for asset impairment could lead to greater volatility in our reported earnings in future periods. The value-in-use test uses discounted future cash flows, thereby increasing the likelihood of asset impairment relative to the undiscounted cash flow test applied under Canadian GAAP. Furthermore, IFRS requires companies to reverse impairment losses (for everything except goodwill) if an impairment is reduced due to a change in circumstances. Canadian GAAP does not allow companies to reverse impairment losses. Our analysis to date indicates that we are unlikely to record significant impairment charges on transition to IFRS. We do, however,


anticipate reversing portions of impairment charges previously recorded under Canadian GAAP. See Opening balances and interim period financial results under IFRS for more information.

Employee benefits

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

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

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

Share-based payments

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

We expect no material impact on our financial results due to this difference.

Provisions (Including asset retirement obligations)

IAS 37, Provisions, Contingent Liabilities and Contingent Assets, requires companies to recognize a provision when:

there is a present obligation due to a past transaction or event

it is probable (i.e. more likely than not) that an outflow of resources will be required to settle the obligation, and

the obligation can be reliably estimated

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

IFRS also measures provisions differently. For example:

When there is a range of equally possible outcomes, IFRS uses the midpoint of the range as the best estimate, while Canadian GAAP uses the low end of the range.

Under IFRS, material provisions are discounted to their present value.

Joint ventures

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

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

Income taxes

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

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

Convertible debentures

Under Canadian GAAP, our convertible debentures, issued in 2003 and redeemed in 2008, were treated as a compound instrument with a debt and equity component. We measured the debt component at amortized cost using


the effective interest rate method, while the equity component was measured at the issue date using the residual method with no future changes in value recognized.

Under IFRS, we have concluded that these convertible debentures cannot be accounted for as compound instruments under IAS 32. The accounting for the debt component is unchanged, but we have concluded that the conversion feature is to be accounted for as a derivative under IFRS. A derivative is required to be measured at fair value at each reporting date with changes in value being recorded in earnings. For purposes of our IFRS transition, we have measured the fair value of the conversion feature as at the redemption date and recorded an increase in share capital offset by a corresponding decrease in retained earnings.

Given the significant increase in value of the conversion option as a result of increases in the stock price of Cameco between the date of issuance and the date of redemption, a reclassification between retained earnings and share capital has been recorded in the amount of $297 million.

Exploration expenses Under Canadian GAAP, we charge expenditures for geological exploration programs to earnings as incurred. Once the decision to proceed to development has been made, subsequent exploration and development expenditures related to the project are then capitalized.

IFRS 6, Exploration for and Evaluation of Mineral Resources, allows companies to either capitalize or expense costs incurred during the exploration and evaluation phase. Geological activities are considered to be classified as exploration and evaluation during the time between obtaining the legal rights to explore a specific area and the completion of a commercially viable technical feasibility study. IFRS 6 requires entities to select and consistently apply an accounting policy specifying which expenditures are capitalized and which are expensed.

On transition to IFRS, we plan to maintain our current accounting policy of expensing all costs relating to exploration and evaluation as they are incurred. As we do under Canadian GAAP, we will capitalize costs once we have determined that a property has economically recoverable reserves. No adjustments are required on transition to IFRS.


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

We have analyzed the options available to us and currently expect to use the exemptions in the table below. This is a summary of the changes we currently believe will be most significant when we transition to IFRS – it is not a complete list of changes we will be required or may elect to make. We have completed our analyses on a preliminary basis but have not yet made final decisions about the accounting policies that are available. We have quantified the majority of the expected impacts of these differences on our consolidated financial statements.

Business combinations We will have the option to apply IFRS 3, Business Combinations, retrospectively or prospectively.

We plan to apply IFRS 3 prospectively to all business combinations that occurred before the transition date, except as required under IFRS 1.

Fair value as deemed cost

We will be able to choose to use the fair value of property, plant and equipment as deemed cost at the transition date, or to use the value determined under GAAP.

We plan to use the historical bases under Canadian GAAP as deemed cost at the transition date.

Share-based payments We will be able to apply IFRS 2, Share-Based Payments, to all equity instruments granted on or before November 7, 2002, and to those granted after November 7, 2002 only if they had not vested by the transition date.

We plan to apply IFRS 2 to all equity instruments granted after November 7, 2002 that had not vested as of January 1, 2010, and to all liabilities arising from share-based payment transactions that existed at January 1, 2010.

Borrowing costs We will be able to choose to apply IAS 23, Borrowing Costs retrospectively, using a date we specify, or to capitalize borrowing costs for all qualifying assets when capitalization begins on or after January 1, 2010.

We plan to apply IAS 23 prospectively. For all qualifying assets, we will expense the borrowing costs we were capitalizing before January 1, 2010, and capitalize the borrowing costs that take effect on or after that date.

Employee benefits IAS 19, Employee Benefits, requires entities to defer or amortize certain actuarial gains and losses, subject to certain provisions (corridor approach), or to immediately recognize them in equity.

We plan to recognize cumulative actuarial gains and losses on benefit plans in retained earnings at the transition date.

Differences in currency translation

IAS 21, The Effects of Changes in Foreign Exchange Rates, will require us to calculate currency translation differences retrospectively, from the date we formed or acquired a subsidiary or associate.

IFRS 1 gives us the option of resetting cumulative translation gains and losses to zero at the transition date.

We plan to reset all cumulative translation gains and losses to zero in retained earnings at the transition date.

Decommissioning liabilities

We will have the option of applying International Financial Reporting Interpretations Committee 1 (IFRIC 1), Changes in Existing Decommissioning, Restoration and Similar Liabilities, retrospectively or prospectively.

IFRIC 1 will require us to add or deduct a change in our obligations to dismantle, remove and restore items of property, plant and equipment, from the cost of the asset it relates to. The adjusted amount is then depreciated prospectively over the asset’s remaining useful life.

We plan to adopt IFRIC 1 prospectively at the transition date.


Opening balances and interim period financial results under IFRS The following tables present our current estimates of the most significant differences in our IFRS balances as at January 1, 2010 and between our Canadian GAAP and IFRS earnings for the three month periods ended March 31, 2010 and June 30, 2010. This information reflects our most recent views, assumptions and expectations. However, circumstances may arise, such as changes in IFRS standards or interpretations of existing IFRS standards, which could alter the information presented below.

This is a summary of the changes we currently believe will be most significant when we transition to IFRS – it is not a complete list of changes we will be required or may elect to make.

The notes referenced in the tables are explained by the corresponding notes at the end of the tables.

Opening balances

Accounting difference

Balance sheet category

Change ($ millions)

Impairment reversal1 Property, plant & equipment 35

Decommissioning liabilities2 Provisions

Property, plant & equipment

55

(55)

Borrowing costs3 Property, plant & equipment (330)

Cumulative translation adjustment4 Cumulative translation adjustment (50)

Employee benefits5 Long-term investments, receivables & other

(15)

Joint venture accounting6 Property, plant & equipment

Long-term debt

Other liabilities

(450)

(170)

(145)

In-process research & development (IPR&D)7

Investments in equity-accounted investees

20

Convertible debentures8 Share capital 297

Income taxes9 Deferred tax liabilities (135)

Amounts closed to retained earnings10 Retained earnings (740)

Net change in shareholders’ equity11 Shareholders’ equity (390)


Interim period financial results

Changes in earnings ($ millions)

Three months ended March 31, 2010

Three months ended June 30, 2010

Net earnings – Canadian GAAP 143 68

Accounting differences

Borrowing costs3

Decommissioning provision2

In-process research & development7

Maintenance costs – BPLP12

Income taxes – tax effect on differences9

Income taxes – IFRS accounting difference9

All other

(10)

(3)

3

-

3

6

1

(10)

(3)

3

8

1

-

2

Total accounting differences - 1

Net earnings – IFRS 143 69

Adjustments

Unrealized losses (gains) on financial instruments

(31)

46

Adjusted net earnings (non-GAAP measure) 112 115

1 IFRS requires the reversal of any previously recorded impairment losses where circumstances have changed such that the impairments have been reduced. We reviewed our previously recorded impairment losses and reversed a portion of the charges relating to certain of our in situ recovery mine assets located in the United States.

2 We plan to elect under IFRS 1 to apply IFRIC 1, Changes in Existing Decommissioning, Restoration and Similar Liabilities prospectively to changes in decommissioning liabilities that occurred prior to January 1, 2010. There are no new liabilities recognized as a result of the transition to IFRS. However, the measurement of existing liabilities according to the IFRS standards will provide a different result. At January 1, 2010, the effect would be a $55 million increase in provisions, a $55 million decrease in property, plant and equipment and a $110 million decrease in retained earnings.

Canadian GAAP requires the unwinding of the discount (accretion) to be recorded as an operating cost and allocated to inventory whereas IFRS requires accretion to be reflected as a financing cost. The net result in the interim periods was an increase in reported expenses with a corresponding decrease in product inventories.

3 We plan to elect under IFRS 1 not to apply IAS 23, Borrowing Costs retrospectively to borrowing costs incurred on the construction of qualifying assets that commenced prior to January 1, 2010. Accordingly, we plan to expense all borrowing costs that had been previously capitalized under Canadian GAAP. New guidance from the IASB is pending and it is possible that our accounting may change as a result.

4 We plan to elect under IFRS 1 to deem all foreign currency translation differences that exist at the date of transition to IFRS to be zero at the date of transition.

5 We plan to elect under IFRS 1 to reclassify all cumulative actuarial gains and losses for all defined benefit plans existing at January 1, 2010 to retained earnings at that date.

6 Under IFRS, we expect to account for our interests in joint ventures that are constituted as a legal entity using the equity method. Under Canadian GAAP, Cameco’s 31.6% interest in BPLP was accounted for using proportionate consolidation. This change to the equity method has a significant impact on certain of our balance sheet categories.

7 Under IFRS, IPR&D that meets the definition of an intangible asset is capitalized with amortization commencing when the asset is ready for use (i.e. when development is complete). Under Canadian GAAP, we have been amortizing IPR&D related to the acquisition of our interest in Global Laser Enrichment LLC, a development stage entity.


For the interim periods, we reversed the full amount amortized under Canadian GAAP.

8 Under IFRS, we have concluded that our convertible debentures issued in 2003 and settled in 2008 will be treated as a hybrid instrument with a debt component and a conversion feature to be accounted for as a derivative. A derivative is required to be measured at fair value at each reporting date with changes in value being recorded in earnings. For purposes of our IFRS transition, we have measured the fair value of the conversion feature as at the redemption date and recorded a $297 million increase in share capital offset by a corresponding decrease in retained earnings.

9 As a result of the changes in our opening balances on transition to IFRS, we expect to reduce our deferred tax liabilities by approximately $135 million.

For the interim periods, the adjustments relating to income tax expense reflect the tax effects of other adjustments as well as an IFRS accounting difference related to intra-group transactions. Under IFRS, deferred tax assets and liabilities are recognized for intra-group transactions whereas Canadian GAAP allows for the recognition of deferred tax assets and liabilities only when the transaction is with a third party.

10 Many of the foregoing changes are closed to retained earnings. We currently expect to reduce our retained earnings amount by approximately $740 million on transition to IFRS. This reduction is largely attributable to the changes to borrowing costs and convertible debentures.

11 Certain adjustments to retained earnings are the result of changes in other components of shareholders’ equity. Thus, the net change in total shareholders’ equity is expected to be significantly lower than the change in retained earnings.

12 Under IFRS the costs of major inspections are capitalized and amortized over the period to the next inspection. Under Canadian GAAP, we have been expensing the inspection costs related to our interest in BPLP.

Other updates

As we proceed with our transition, we are also assessing the impact on our internal controls over financial reporting, and on our disclosure controls and procedures. Changes in accounting policies or business processes require the implementation of additional controls or procedures to ensure the integrity of our financial disclosures. We have substantially completed the design of the necessary new controls and testing is ongoing. We do not, however, anticipate any significant changes to be required in our internal control over financial reporting or our disclosure controls and procedures as a result of the transition to IFRS.

We conducted several educational and training sessions for our audit committee and the board of directors in 2009 and 2010. During these sessions, management and external advisors provided the board with detailed background information on IFRS accounting standards (including IFRS 1 elections), the implications of policy choices on our financial reporting, and a preliminary view of the expected format and content of our financial statements and notes upon transition. Management gives the audit committee quarterly project status updates and presentations.

We began training management and accounting staff in 2008. Training is being delivered mainly by external advisors, and focusing on the accounting issues most relevant to Cameco. Sessions will continue throughout 2010. As a result, we are confident there is sufficient expertise within the organization to allow us to effectively transition to IFRS.

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

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

Cameco CorporationHighlights(Unaudited)

Sep 30/10 Sep 30/09 Sep 30/10 Sep 30/09

Financial (in millions)

Revenue $419 $518 $1,450 $1,656

Net earnings 98 172 308 501

Adjusted net earnings 80 94 305 358 Cash provided by (used in) operations (18) 175 387 502

Working capital (end of period) 1,812 1,362

Net debt to capitalization N/A 13%

Per common share

Net earnings - Basic $0.25 $0.44 $0.78 $1.30

- Diluted 0.25 0.44 0.78 1.29

- Diluted, adjusted 0.20 0.24 0.77 0.92

Dividend 0.07 0.06 0.21 0.18

Weighted average number of paid common shares outstanding (in thousands) 393,100 392,613 392,988 386,355

Uranium price informationAverage uranium spot price for the period (US$/lb) $45.83 $45.29 $43.01 $46.10Average uranium realized price for the period (US$/lb) 40.63 34.24 41.46 37.26Average uranium realized price for the period (Cdn$/lb) 43.01 39.18 43.90 45.80

Sales volumesUranium (in thousands lbs U3O8) 5,572 8,280 20,514 23,883

Fuel services (tU) 3,939 2,833 10,731 8,853Electricity (TWh) 2.0 1.9 6.1 5.8

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

Cameco's

Cameco Production Share Sep 30/10 Sep 30/09 Sep 30/10 Sep 30/09

Uranium production (in thousands lbs U3O8)

McArthur River 69.8% 3,703 3,758 9,882 9,325

Rabbit Lake 100.0% 476 918 2,558 2,415

Crow Butte 100.0% 188 198 554 554Smith Ranch Highland 100.0% 427 410 1,354 1,300Inkai 60.0% 763 343 2,110 536

Total 5,557 5,627 16,458 14,130

Fuel services (tU) (i) 100.0% 2,331 4,088 11,673 8,449

(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) (Recast (Recast

note 12) note 12)

Sep 30/10 Sep 30/09 Sep 30/10 Sep 30/09

Revenue fromProducts and services $419,475 $517,705 $1,450,245 $1,656,279

Expenses

Products and services sold 203,857 302,134 770,600 937,485

Depreciation, depletion and reclamation 63,338 66,849 180,869 174,298

Administration 40,205 32,789 101,258 93,706

Exploration 35,430 10,654 68,340 33,074

Research and development 1,033 (2,299) 2,654 (86)Interest and other [note 7] 1,894 3,860 7,303 (10,899)Gains on derivatives [note 4] (39,099) (128,975) (22,049) (201,219)

Cigar Lake remediation 6,622 2,927 14,460 13,119 Loss (gain) on sale of assets (481) 2,337 (297) 183

312,799 290,276 1,123,138 1,039,661

Earnings from continuing operations 106,676 227,429 327,107 616,618

Other expense (4,891) (4,686) (10,795) (24,706)

Earnings before income taxes and minority interest 101,785 222,743 316,312 591,912

Income tax expense [note 8] 7,824 28,376 14,738 50,462Minority interest (3,652) (470) (6,635) (1,175)

Earnings from continuing operations 97,613 194,837 308,209 542,625 Loss from discontinued operations [note 12] - (22,722) - (41,663)

Net earnings $97,613 $172,115 $308,209 $500,962

Net earnings per share [note 9]

Basic

Continuing operations $0.25 $0.50 $0.78 $1.40Discontinued operations - (0.06) - (0.10)

$0.25 $0.44 $0.78 $1.30

Diluted

Continuing operations $0.25 $0.50 $0.78 $1.40Discontinued operations - (0.06) - (0.11)

$0.25 $0.44 $0.78 $1.29

Nine Months EndedThree Months Ended

See accompanying notes to consolidated financial statements

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

Sep 30/10 Dec 31/09

Assets

Current assets

Cash and cash equivalents $353,637 $1,101,229

Short-term investments 916,787 202,836

Accounts receivable 357,570 453,622

Inventories [note 3] 514,230 453,224

Supplies and prepaid expenses 171,249 162,105

Current portion of long-term receivables, investments and other [note 5] 86,492 154,725

2,399,965 2,527,741

Property, plant and equipment 4,245,743 4,068,103

Intangible assets 95,218 97,713

Long-term receivables, investments and other [note 5] 651,491 648,545

Future income tax assets 34,801 33,017

5,027,253 4,847,378

Total assets $7,427,218 $7,375,119

Liabilities and Shareholders' Equity

Current liabilities

Accounts payable and accrued liabilities [note 8] $390,477 $534,664

Short-term debt 75,530 76,762

Dividends payable 27,542 23,570

Current portion of long-term debt 12,766 11,629

Current portion of other liabilities 46,730 29,297

Future income tax liabilities 35,418 87,135

588,463 763,057

Long-term debt 943,534 952,853

Provision for reclamation 299,814 296,896

Other liabilities 194,786 187,072

Future income tax liabilities 172,000 167,373

2,198,597 2,367,251

Minority interest 174,132 164,040

Shareholders' equity

Share capital 1,518,794 1,512,461

Contributed surplus 138,155 131,577

Retained earnings 3,384,154 3,158,506

Accumulated other comprehensive income 13,386 41,284

5,054,489 4,843,828

Total liabilities and shareholders' equity $7,427,218 $7,375,119

Commitments and contingencies [notes 8,13]

As At


Cameco CorporationConsolidated Statements of Shareholders' Equity(Unaudited) (Recast

($Cdn Thousands) note 12)

Sep 30/10 Sep 30/09

Share capital

Balance at beginning of period $1,512,461 $1,062,714Stock option plan 6,333 5,487 Equity issuance [note 6] - 445,532

Balance at end of period $1,518,794 $1,513,733

Contributed surplus

Balance at beginning of period $131,577 $131,858Stock-based compensation 7,646 4,917 Options exercised (1,068) (406)

Balance at end of period $138,155 $136,369

Retained earnings

Balance at beginning of period $3,158,506 $2,153,315Net earnings 308,209 500,962 Dividends on common shares (82,561) (70,660)

Balance at end of period $3,384,154 $2,583,617

Accumulated other comprehensive income (loss)

Balance at beginning of period $41,284 $165,736Other comprehensive income (loss) (27,898) (58,468)

Balance at end of period $13,386 $107,268

Total retained earnings and accumulated other comprehensive income $3,397,540 $2,690,885

Shareholders' equity at end of period $5,054,489 $4,340,987

Nine Months Ended


Cameco CorporationConsolidated Statements of Comprehensive Income(Unaudited) (Recast (Recast

($Cdn Thousands) note 12) note 12)

Sep 30/10 Sep 30/09 Sep 30/10 Sep 30/09

Net earnings $97,613 $172,115 $308,209 $500,962Other comprehensive income (loss), net of taxes [note 8]

Unrealized foreign currency translation gains (losses) 14,375 (60,548) 12,792 (87,686) Gains on derivatives designated as cash flow hedges 1,826 29,983 12,130 114,385 Gains on derivatives designated as cash flow hedges

transferred to net earnings (14,760) (32,481) (51,278) (87,317) Unrealized gains on available-for-sale securities 139 390 1,072 2,150 Losses (gains) on available-for-sale securities transferred to net earnings 15 - (2,614) -

Other comprehensive income (loss) 1,595 (62,656) (27,898) (58,468)

Total comprehensive income $99,208 $109,459 $280,311 $442,494

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

CurrencyTranslation Cash Flow Available-For-

(net of related income taxes)[note 8] Adjustment Hedges Sale Assets Total

Balance at December 31, 2009 ($50,397) $89,456 $2,225 $41,284Unrealized foreign currency translation gains 12,792 - - 12,792 Gains on derivatives designated as cash flow hedges - 12,130 - 12,130 Gains on derivatives designated as cash flow hedges

transferred to net earnings - (51,278) - (51,278) Unrealized gains on available-for-sale securities - - 1,072 1,072 Gains on available-for-sale securities transferred to net earnings - - (2,614) (2,614)

Balance at September 30, 2010 ($37,605) $50,308 $683 $13,386

Balance at December 31, 2008 $65,342 $101,654 ($1,260) $165,736Unrealized foreign currency translation losses (87,686) - - (87,686) Gains on derivatives designated as cash flow hedges - 114,385 - 114,385 Gains on derivatives designated as cash flow hedges

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

Balance at September 30, 2009 ($22,344) $128,722 $890 $107,268



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

note 12) note 12)

Sep 30/10 Sep 30/09 Sep 30/10 Sep 30/09

Operating activities

Net earnings $97,613 $172,115 $308,209 $500,962

Items not requiring (providing) cash:

Depreciation, depletion and reclamation 63,338 66,849 180,869 174,298

Provision for future taxes [note 8] (300) 22,470 (33,289) 5,141

Deferred gains (6,534) (8,790) (24,436) (33,102)

Unrealized losses (gains) on derivatives (31,552) (84,296) 64,640 (197,315)

Stock-based compensation [note 10] 1,323 565 7,645 3,802

Loss (gain) on sale of assets (481) 2,337 (297) 183

Equity in loss of associated companies 4,891 4,686 13,428 24,706

Other income - - (2,633) -

Discontinued operations - 22,722 - 41,663

Minority interest (3,652) (470) (6,635) (1,175)

Other operating items [note 11] (142,451) (22,820) (120,426) (17,256)

Cash provided by (used in) operations (17,805) 175,368 387,075 501,907

Investing activitiesAdditions to property, plant and equipment (120,253) (87,242) (330,224) (276,829) Purchase of short-term investments 53,759 (16,979) (714,271) (16,979) Increase in long-term receivables, investments and other (3,079) (12,096) (15,312) (35,832)

Proceeds on sale of property, plant and equipment 481 52 5,946 3,685

Cash used in investing (69,092) (116,265) (1,053,861) (325,955)

Financing activities

Decrease in debt (1,674) (237,713) (11,186) (607,367)

Issue of debentures, net of issue costs - 495,818 - 495,818

Contributions from minority interests 3,008 - 7,646 -

Issue of shares, net of issue costs [note 6] - - - 440,150

Issue of shares, stock option plan 2,999 1,023 5,266 2,318

Dividends (27,512) (23,553) (78,590) (69,044)

Cash provided by (used in) financing (23,179) 235,575 (76,864) 261,875

Increase (decrease) in cash during the period (110,076) 294,678 (743,650) 437,827

Exchange rate changes on foreign currency cash balances (1,327) (8,700) (3,942) (6,739)

Cash and cash equivalents at beginning of period 465,040 209,332 1,101,229 64,222

Cash and cash equivalents at end of period $353,637 $495,310 $353,637 $495,310

Cash and cash equivalents comprised of:Cash $68,798 $40,114Cash equivalents 284,839 455,196

$353,637 $495,310

Supplemental cash flow disclosureInterest paid $24,321 $10,894 $51,835 $31,889Income taxes paid ($6,485) $6,838 $47,585 $52,783



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. Since the interim financial statements do not include all disclosures required by GAAP for annual financial statements, they should be read in conjunction with Cameco’s annual consolidated financial statements included in the 2009 annual financial review. Certain comparative figures for the prior period have been reclassified to conform to the current period’s presentation.

2. Future Changes in Accounting Policy

International Financial Reporting Standards (IFRS) In February 2008, the Accounting Standards Board announced that Canadian publicly accountable enterprises will be required to adopt IFRS effective January 1, 2011. As a result, Cameco will publish its first consolidated financial statements, prepared in accordance with IFRS, for the quarter ending March 31, 2011. We will also provide comparative data on an IFRS basis, including an opening balance sheet as at January 1, 2010.

3. Inventories

(thousands) Sep 30/10 Dec 31/09

Uranium Concentrate $344,493 $310,893 Broken ore 19,764 18,125

364,257 329,018

Fuel Services 149,973 124,206

Total $514,230 $453,224

As At

4. Derivatives

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

As at September 30, 2010

Current Quarter

(thousands) Cameco BPLP Total

Non-hedge derivatives: Embedded derivatives - sales contracts $(3,330) $29,281 $25,951 Foreign currency contracts 4,454 - 4,454 Interest rate contracts 3,557 - 3,557 Cash flow hedges: Energy and sales contracts - 38,171 38,171

Net $4,681 $67,452 $72,133

Classification: Current portion of long-term receivables, investments and other [note 5] $19,092 $61,188 $80,280 Long-term receivables, investments and other [note 5] 4,781 43,038 47,819 Current portion of other liabilities (14,481) (22,815) (37,296) Other liabilities (4,711) (13,959) (18,670)

Net $4,681 $67,452 $72,133


As at December 31, 2009 Previous Year


Non-hedge derivatives: Embedded derivatives - sales contracts $(2,736) $9,082 $6,346 Foreign currency contracts 67,031 - 67,031 Cash flow hedges: Energy and sales contracts - 96,047 96,047

Net $64,295 $105,129 $169,424

Classification: Current portion of long-term receivables, investments and other [note 5] $66,972 $87,439 $154,411 Long-term receivables, investments and other [note 5] 1,460 54,510 55,970 Current portion of other liabilities (445) (19,595) (20,040) Other liabilities (3,692) (17,225) (20,917)

Net $64,295 $105,129 $169,424 The following tables summarize different components of the (gains) and losses on derivatives:

For the three months ended September 30, 2010


Non-hedge derivatives: Embedded derivatives - sales contracts $(2,599) $3,315 $716 Foreign currency contracts (36,940) - (36,940) Interest rate contracts (3,234) - (3,234) Cash flow hedges: Energy and sales contracts - 359 359

Net $(42,773) $3,674 $(39,099)

For the three months ended September 30, 2009


Non-hedge derivatives: Embedded derivatives - sales contracts $1,812 $(2,086) $(274) Foreign currency contracts (128,854) - (128,854) Cash flow hedges: Energy and sales contracts - 153 153

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


For the nine months ended September 30, 2010


Non-hedge derivatives: Embedded derivatives - sales contracts $637 $2,932 $3,569 Foreign currency contracts (22,999) - (22,999) Interest rate contracts (4,582) - (4,582) Cash flow hedges: Energy and sales contracts - 1,963 1,963

Net $(26,944) $4,895 $(22,049)



Non-hedge derivatives: Embedded derivatives - sales contracts $(4,307) $(3,914) $(8,221) Foreign currency contracts (193,194) - (193,194) Cash flow hedges: Energy and sales contracts - 196 196

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

Over the next 12 months, based on current exchange rates, Cameco expects an estimated $14,958,000 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 $18,882,000 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) Sep 30/10 Dec 31/09

Bruce B L.P. (BPLP) Capital lease receivable from BALP $92,462 $94,895 Derivatives [note 4] 104,226 141,949 Accrued pension benefit asset 61,336 36,613 Equity accounted investments Global Laser Enrichment LLC (privately held) 172,047 185,716 UEX Corporation (market value $46,319) 8,182 6,052 Huron Wind (privately held) 3,802 4,002 Minergia S.A.C. (privately held) 3,709 4,551 UFP Investments Inc. (privately held) 7,537 2,617 Available-for-sale securities Western Uranium Corporation (market value $4,916) 4,916 4,637 GoviEx Uranium (privately held) 24,236 25,214 Derivatives [note 4] 23,873 68,432 Deferred charges Cost of sales 14,415 14,415 Advances receivable from Inkai JV LLP 148,834 141,149 Accrued pension benefit asset 5,109 7,773 Other 63,299 65,255

737,983 803,270 Less current portion (86,492) (154,725)

Net $651,491 $648,545

6. Share Capital

(a) At September 30, 2010, there were 393,458,577 common shares outstanding. (b) Options in respect of 8,537,951 shares are outstanding under the stock option plan and are exercisable up to

2018. For the quarter ended September 30, 2010, 432,652 options were exercised resulting in the issuance of shares (2009 – 89,190). For the nine months ended September 30, 2010, 619,844 options were exercised resulting in the issuance of shares (2009 – 269,550).

(c) On March 5, 2009, Cameco 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 were $445,532,000. Excluding the deferred tax recoveries, our net cash proceeds amounted to $440,150,000 in 2009.

7. Interest and Other

Three Months Ended Nine Months Ended(thousands) Sep 30/10 Sep 30/09 Sep 30/10 Sep 30/09

Interest on long-term debt $12,187 $6,868 $36,815 $24,263Interest on short-term debt 554 486 1,458 1,905 Foreign exchange losses (gains) 2,262 1,915 5,627 (18,232) Other charges 2,069 3,337 6,722 10,302 Interest income (3,678) (1,219) (8,310) (3,910) Capitalized interest (11,500) (7,527) (35,009) (25,227)

Net $1,894 $3,860 $7,303 $(10,899)


8. Income Tax Expense


Earnings (loss) before income taxes andminority interest Canada $6,600 $27,704 $(39,678) $60,974 Foreign 95,185 195,039 355,990 530,938

$101,785 $222,743 $316,312 $591,912

Current income taxes Canada $3,218 $(5,141) $29,382 $19,158 Foreign 4,906 11,046 18,645 26,163

$8,124 $5,905 $48,027 $45,321Future income taxes (recovery) Canada $1,511 $29,327 $(33,117) $10,512 Foreign (1,811) (6,856) (172) (5,371)

$(300) $22,471 $(33,289) $5,141

Income tax expense $7,824 $28,376 $14,738 $50,462

At September 30, 2010, current taxes payable in the amount of $30,765,000 (December 31, 2009 - $31,140,000), have been included in accounts payable and accrued liabilities.

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 income for Canadian income tax purposes by approximately $43,000,000 (this reassessment was superseded by a reassessment issued in February 2009). In December 2009, CRA issued a notice of reassessment for the 2004 taxation year, which increased Cameco’s 2004 income by approximately $108,000,000. Another reassessment for 2004 was issued by CRA on May 13, 2010 to similar effect. No reassessment received to date has resulted in more than a nominal amount of cash taxes becoming payable due to availability of elective deductions and tax loss carrybacks. Cameco believes it is likely that CRA will reassess Cameco’s tax returns for the years 2005 through 2009 on a similar basis.

Late in 2009, CRA’s Transfer Pricing Review Committee decided not to impose a penalty for 2004 based on the documentation that had been submitted by Cameco. This followed the same decision by the Transfer Pricing Review Committee late in 2008 for the 2003 notice of reassessment.

Having regard to advice from its external advisors, Cameco’s opinion is that CRA’s position is incorrect, and Cameco is contesting CRA’s position. However, to reflect the uncertainties of CRA’s appeals process and litigation, Cameco decided to increase its reserve for uncertain tax positions and recognize an income tax expense of $9,000,000 in 2009, bringing the cumulative tax provision related to this matter for the years 2003 through 2009 to $24,000,000. No provisions for penalties or interest have been recorded. We do not expect more than a nominal amount of cash taxes to be payable due to availability of elective deductions and tax loss carryovers. 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 2009 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 reassessments, a Notice of Appeal for the 2003 taxation year was filed with the Tax Court of Canada on July 22, 2009 and the litigation process is proceeding. In connection with CRA’s 2004 reassessment, Cameco is contesting the reassessment and pursuing its appeal rights under the Income Tax Act.


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) Sep 30/10 Sep 30/09 Sep 30/10 Sep 30/09

Gains on derivatives designated as cash flow hedges $659 $12,931 $2,795 $52,060Gains on derivatives designated as cash flow hedges transferred to net earnings (6,008) (13,525) (21,152) (35,797) Unrealized gains on assets available-for-sale 29 61 161 336 Losses (gains) on assets available-for-sale transferred to net earnings 3 - (409) -

Total income tax expense (recovery) included in OCI $(5,317) $(533) $(18,605) $16,599


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) Sep 30/10 Sep 30/09

Gains on derivatives designated as cash flow hedges $18,630 $53,003Unrealized gains on assets available-for-sale 100 139

Total income tax expense included in AOCI $18,730 $53,142

As At


9. Per Share Amounts


Basic earnings per share computation

Net earnings $97,613 $172,115 $308,209 $500,962

Weighted average common sharesoutstanding 393,100 392,613 392,988 386,355

Basic earnings per common share $0.25 $0.44 $0.78 $1.30

Diluted earnings per share computation

Net earnings $97,613 $172,115 $308,209 $500,962

Weighted average common shares outstanding 393,100 392,613 392,988 386,355

Dilutive effect of stock options 1,483 2,120 1,645 1,872

Weighted average common sharesoutstanding, assuming dilution 394,583 394,733 394,633 388,227

Diluted earnings per common share $0.25 $0.44 $0.78 $1.29

For the nine months ended September 30, 2010, excluded from the calculation were 5,979,096 options whose exercise price was greater than the average closing market price (2009 – 4,793,053). For the quarter ended September 30, 2010, excluded from the calculation were 5,979,096 options as their exercise price was greater than the average closing market price (2009 – 3,236,411).

10. 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. Options granted under the stock option plan have an exercise price of not less than the closing price quoted on the TSX for the common shares of Cameco on the trading day prior to the date on which the option is granted. The options vest over three years and expire eight years from the date granted. Options have not been awarded to directors since 2003 and the plan has been amended to preclude the issue of options to directors.

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 25,199,973 shares have been issued.

Cameco records compensation expense 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, 2010, the amount recorded was $1,324,000 (2009 - $566,000). For the nine months ended September 30, 2010, the amount recorded was $7,645,000 (2009 - $3,803,000).


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

Nine Months EndedSep 30/10 Sep 30/09

Number of options granted 1,515,945 1,381,039 Average strike price $28.90 $19.41Expected dividend $0.28 $0.24Expected volatility 36% 36%Risk-free interest rate 2.1% 1.6%Expected life of option 4.2 years 4.0 yearsExpected forfeitures 15% 15%Weighted average grant date fair values $8.46 $5.21

11. Statements of Cash Flows Other Operating Items


Accounts receivable $(90,245) $(1,450) $97,072 $213,642Inventories (65,883) (9,960) (50,913) (60,488) Accounts payable and accrued liabilities 42,386 (8,235) (141,163) (106,451) Other (28,709) (3,175) (25,422) (63,959)

Total $(142,451) $(22,820) $(120,426) $(17,256)

12. Restructuring of the Gold Business The assets and liabilities related to discontinued operations have been reclassified as assets or liabilities of discontinued operations on the consolidated balance sheets. Operating results related to the discontinued operations have been included in earnings from discontinued operations on the consolidated statements of earnings. Comparative period balances have been restated.

(a) Sale of Centerra Gold Inc. On December 30, 2009, Cameco completed a public offering of 88,618,472 common shares of Centerra. Concurrent with this offering, Cameco transferred an additional 25,300,000 common shares of Centerra to Kyrgyzaltyn pursuant to the agreement that Cameco entered into with the Government of the Kyrgyz Republic on April 24, 2009. As a result of these two transactions, Cameco has disposed of its entire interest in Centerra.

(b) Financial Results of Discontinued Operations The results of the operations of Centerra are presented under “discontinued operations” on the consolidated statements of earnings. The following table presents the components of the discontinued operations amounts, net of future income tax expenses:


Kyrgyz share transfer $ - $(33,482) $ - $(17,551)Operating earnings (loss) - 10,760 - (24,112)

Loss from discontinued operations $ - $(22,722) $ - $(41,663)


The following table presents the components of the operating results of Centerra:


Revenue $ - $176,398 $ - $426,801

Expenses Products and services sold - 105,599 - 315,326 Depreciation, depletion and reclamation - 30,480 - 90,594 Exploration - 7,550 - 19,433 Other - 8,857 - 25,573

Earnings (loss) before income taxes and minority interest - 23,912 - (24,125) Income tax expense - 2,680 - 16,846 Minority interest - 10,472 - (16,859)

Operating earnings (loss) $ - $10,760 $ - $(24,112)

13. 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 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 has 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 the discovery process and the arbitration hearing is currently underway.


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. Further proceedings in this action are on hold pending completion of the arbitration hearing.

(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) Guarantees to customers under power sale agreements of up to $35,300,000. At September 30, 2010, Cameco’s actual exposure under these guarantees was $27,900,000.

(ii) 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. BPLP’s entitlement to receive these payments remains in effect until December 31, 2019 but the generation that is subject to these payments starts to decrease in 2016, reflecting the original estimated lives for the Bruce B units. During 2010, BPLP recorded $224,000,000 under this agreement which was recognized as revenue with Cameco’s share being $71,000,000.

14. Related Party Transactions Cameco purchases a significant amount of goods and services for its Saskatchewan mining operations from northern Saskatchewan suppliers to support economic development in the region. One such supplier is Points Athabasca Contracting Ltd. and the president of the company became a member of the board of directors of Cameco during 2009. During the first nine months of 2010, Cameco paid Points Athabasca Contracting Ltd. $19,000,000 (2009 - $21,600,000) for construction and contracting services. The transactions were conducted in the normal course of business and were accounted for at the exchange amount. Accounts payable include a balance of $1,120,000 (2009 - $110,000) resulting from these transactions.


15. Segmented Information For the three months ended September 30, 2010

Fuel Inter-(thousands) Uranium Services Electricity Segment Total

Revenue $243,938 $69,258 $114,866 $(8,587) $419,475

Expenses

Products and services sold (i) 99,899 52,950 59,174 (8,166) 203,857

Depreciation, depletion and reclamation 43,271 7,422 13,387 (742) 63,338

Exploration 35,430 - - - 35,430 Other expense 1,282 3,608 - - 4,890

Cigar Lake remediation 6,622 - - - 6,622

Gain on sale of assets (481) - - - (481) Non-segmented expenses 4,034

Earnings before income taxes

and minority interest 57,915 5,278 42,305 321 101,785 Income tax expense [note 8] 7,824

Minority interest (3,652)

Net earnings from continuing operations $97,613

(i) Products and services sold excludes depreciation,

depletion and reclamation expenses of: $39,677 $7,422 $13,387 $(742) $59,744

For the three months ended September 30, 2009 (Recast)


Revenue $328,897 $50,433 $144,823 $(6,448) $517,705

Expenses



Exploration 10,654 - - - 10,654 Other expense 753 3,951 - - 4,704


Loss on sale of assets 2,337 - - - 2,337 Non-segmented expenses (94,643)

Earnings (loss) before income taxes

and minority interest 52,132 (242) 75,862 348 222,743 Income tax expense [note 8] 28,376

Minority interest (470)







Revenue $912,165 $207,641 $352,688 $(22,249) $1,450,245

Expenses



Exploration 68,340 - - - 68,340 Other expense 165 10,773 - - 10,938


Gain on sale of assets (297) - - - (297) Non-segmented expenses 89,023

Earnings before income taxes

and minority interest 239,230 38,336 124,953 2,816 316,312 Income tax expense [note 8] 14,738





For the nine months ended September 30, 2009 (Recast)


Revenue $1,107,909 $185,619 $384,825 $(22,074) $1,656,279

Expenses


Depreciation, depletion and reclamation 114,840 16,973 42,256 229 174,298

Exploration 33,074 - - - 33,074 Other expense 6,508 18,402 - - 24,910


Loss on sale of assets 183 - - - 183 Non-segmented expenses (118,702)

Earnings (loss) before income taxes

and minority interest 303,015 18,032 157,651 (5,488) 591,912 Income tax expense [note 8] 50,462




depletion and reclamation expenses of: $106,887 $16,973 $42,256 $229 $166,345

management’s discussion and analysis · 2015. 4. 23. · 2010 third quarter report 1...

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