Cameco reports third quarter financial results Quarterly items reconfirmed sales, revenue and production guidance for the year increased mineral reserves by 19% at McArthur River signed an MOA with our joint venture partner at Inkai
TSX: CCO website: cameco.com NYSE: CCJ currency: Cdn (unless noted)
2121 – 11th Street West, Saskatoon, Saskatchewan, S7M 1J3 Canada Tel: (306) 956-6200 Fax: (306) 956-6201
Cameco reports third quarter financial results
Quarterly items
- reconfirmed sales, revenue and production guidance for the year
- increased mineral reserves by 19% at McArthur River
- signed an MOA with our joint venture partner at Inkai
- received funding commitment from the Saskatchewan government to construct a highway connecting
McArthur River and Cigar Lake
Long-term growth plan
- strong long-term industry fundamentals – 64 reactors under construction
- ongoing market uncertainties reduce uranium demand forecast to 2021
- our growth plan adjusted to focus primarily on our brownfield projects resulting in annual supply of 36
million pounds by 2018
- maintain our world class portfolio of projects, providing the ability to respond to positive market signals
Saskatoon, Saskatchewan, Canada, October 31, 2012 . . . . . . . . . . . . . . . . . . .
Cameco (TSX: CCO; NYSE: CCJ) today reported its consolidated financial and operating results for the third quarter ended September 30, 2012 in accordance with International Financial Reporting Standards (IFRS).
“Our results this quarter reflect the delivery pattern we reported in our second quarter report and we still expect to deliver on our sales, revenue and production guidance for the year,” said Tim Gitzel, president and CEO.
“Longer term, we continue to see strong fundamentals. However, ongoing market uncertainty in the near term led us to review and adjust our growth plans this quarter. We decided to focus on advancing projects with the greatest certainty in the near term, from which we expect to achieve about 36 million pounds of annual supply by 2018 compared to the 40 million previously targeted. We will also continue with the rest of our projects in a measured manner in order to preserve the option to bring them on as quickly as possible, if profitable.
“By taking these actions, we expect to spread our capital spending over a longer period and decrease project-related expenses. Our focus will be on execution and reducing costs without compromising on our values.
“With this adjustment, we believe we are positioned to continue to succeed in the current market environment, add value for our shareholders, and take advantage of the growth in uranium demand we see long term.”
| Highlights ($ millions except where indicated) | Three months | Nine months | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ended September 30 | ended September 30 | |||||||||
| 2012 | 2011 | change | 2012 | 2011 | change | |||||
| Revenue | 408 | 527 (23)% | 1,363 | 1,414 (4)% | ||||||
| Gross profit | 135 | 179 (25)% | 416 | 423 (2)% | ||||||
| Net earnings | 82 | 39 110% | 221 | 186 19% | ||||||
| $ per common share (diluted) | 0.21 | 0.10 110% | 0.56 | 0.47 19% | ||||||
| Adjusted net earnings (non-IFRS, see page 7) | 52 | 104 (50)% | 210 | 259 (19)% | ||||||
| $ per common share (adjusted and diluted) | 0.13 | 0.26 (50)% | 0.53 | 0.66 (20)% | ||||||
| Cash provided by operations (after working capital changes) | 44 | 192 (77)% | 361 | 487 (26)% | ||||||
| Average realized prices $US/lb Uranium $Cdn/lb Fuel services $Cdn/kgU Electricity $Cdn/MWh | 44.49 | 47.33 (6)% 45.97 (2)% | 45.76 | 47.06 (3)% 46.36 - | ||||||
| 44.99 | 46.22 | |||||||||
| 16.98 | 17.42 (3)% | 17.55 | 18.04 (3)% | |||||||
| 54.00 | 54.00 - | 55.00 | 54.00 2% |
Third quarter
Net earnings attributable to our shareholders (net earnings) this quarter were $82 million ($0.21 per share diluted) compared to $39 million ($0.10 per share diluted) in the third quarter of 2011. In addition to the items noted below, net earnings were impacted by higher mark-to-market gains on foreign exchange derivatives.
On an adjusted basis, our earnings this quarter were $52 million ($0.13 per share diluted) compared to $104 million ($0.26 per share diluted) (non-IFRS measure, see pages 7) in the third quarter of 2011, mainly due to:
- lower earnings from our uranium business based on lower sales volumes, lower realized prices and higher costs
- higher expenditures for exploration and administration
partially offset by higher earnings from our electricity business due to an increase in sales and lower costs
See Financial results by segment on page 8 for more detailed discussion.
First nine months
Net earnings in the first nine months of the year were $221 million ($0.56 per share diluted) compared to $186 million ($0.47 per share diluted) in the first nine months of 2011. Net earnings were higher than in 2011 due to higher markto-market gains on foreign exchange derivatives and the items noted below.
On an adjusted basis, our earnings for the first nine months of this year were $210 million ($0.53 per share diluted) compared to $259 million ($0.66 per share diluted) (non-IFRS measure, see pages 7). The change was due to:
- lower earnings from our uranium business based on lower sales volumes, lower realized prices and higher costs
- a $30 million (US) contract termination charge
- higher expenditures for exploration and administration
partially offset by higher earnings from our electricity business due to an increase in sales, higher realized prices and lower costs
See Financial results by segment on page 8 for more detailed discussion.
Our strategy
We remain confident in the long-term fundamentals of the nuclear industry as world demand for safe, clean, reliable and affordable energy continues to grow. Nuclear energy remains an integral part of the energy mix, demonstrated by the 64 reactors under construction today.
However, recent developments in the nuclear industry, primarily centred around Japan, have caused more uncertainty in the rate of growth in nuclear power globally. This led us to review and adjust our outlook, and examine our long-term growth plans.
While market factors continue to evolve, our current view is that over the next decade (to 2021), we expect there will be 80 net new reactors, compared to the 95 previously anticipated. Most of this change is due to the retirement of some reactors and new reactor builds being pushed out beyond the 10-year period. As a result, we have revised our cumulative world uranium demand forecast to 2.1 billion pounds for that period, down 50 million pounds from our previous expectation. As always, we will continue to evaluate the effects on demand as the nuclear market evolves.
Given this expected near-term decrease in demand, we examined our portfolio of projects to determine if we should adjust the timing of development for them. From this review, we have decided to focus primarily on advancing our brownfield projects, while deferring development of our greenfield projects. However, we will undertake some measured activity to preserve the option to bring on these greenfield projects as quickly as possible should market conditions warrant doing so. In addition, we will advance our arrangement with Talvivaara and pace the expansion projects at Inkai. By taking these actions we expect to achieve about 36 million pounds of annual supply rather than 40 million pounds by 2018.
This means we plan to spread our capital spending over a longer period and decrease project-related expenses, which should enhance our nearer term financial picture. Subject to market conditions, we plan to undertake the following projects:
- bring Cigar Lake project to production
- expand production at the McArthur River mine
- refurbish and expand the Key Lake mill
- work to extend the Rabbit Lake mine life
- expand our US ISR production by advancing our various satellite operations
- advance the process for extracting uranium from the Talvivaara mine
Market opportunities will drive the rate of development of the following projects:
- advancing the Millennium project to achieve regulatory approvals as soon as possible to allow development to occur independently
- pacing the increase in uranium production at Inkai blocks 1 and 2 to match progress on the transfer of our refining/conversion technology, both subject to market conditions, and continuing work on the test leach facility at block 3
- completing the value engineering and the environmental permitting at Kintyre, but not proceeding with the detailed feasibility study
Of course, we will adjust the timing of our projects should market conditions evolve, which could change our supply plan. Adjusting a growth plan is not unique in our industry. A number of uranium producers have halted or delayed projects because they are not economic in today’s environment. These economic challenges, driven by continued global economic turmoil and the issues surrounding nuclear power noted above, point to an uncertain future supply of global primary uranium production. And to fuel the 431 currently operating reactors, the 64 reactors under construction today, and the further growth we expect by 2021, new primary sources of production will be needed. We anticipate economics will eventually need to reflect the realities of bringing on new, higher cost production; it’s a matter of timing.
As a result, we continue to prepare our assets now to ensure we can be among the first to respond when the market signals that new production is needed, and project economics improve. We want to be clear that any decision to increase our supply will be driven by profitability.
In the meantime, today’s market environment calls for us to increase our focus on execution and maximize efficiencies in order to continually improve our margins to ensure we remain competitive. Specifically, we are in the process of reducing costs at all operations and corporate departments without compromising our values. In addition, we plan to decrease expenditures for exploration and research and development to better match market opportunities.
We maintain a strong balance sheet, which will be enhanced by taking these actions. As part of our normal strategic planning process, we will continue to review our capital structure and asset base to ensure it is optimal.
Our extraordinary assets, extensive portfolio of long-term sales contracts, employee expertise and comprehensive industry knowledge provide us with the confidence that we will be able to achieve these goals. And, as always, we will look for opportunities across the nuclear fuel cycle that we expect will complement and enhance our business.
We will continue to monitor the market closely and adjust our plans accordingly.
Uranium market update
Since the previous quarter, the nuclear industry continues to experience near- to medium-term uncertainty, driven primarily by the evolving situation in Japan.
In September 2012, a Japanese government panel announced a draft energy policy that included plans to phase out nuclear power generation by 2040. But the plan drew intense opposition from business groups and communities whose economies depend on the local nuclear power plants. The Japanese government did not adopt the plan, but agreed to take it under consideration while engaging with local governments, the public and the international community in developing an energy policy.
Japan’s new Nuclear Regulatory Authority (NRA) also came into effect in September. It will create new regulatory standards against which reactor restarts will be evaluated. We believe the NRA brings important stability to the regulatory environment in Japan and has already brought some clarity to the issue of reactor restarts. It indicated that no additional reactors will be restarted until the new standards are in place – a process expected to take about 10 months. This requirement suggests there will be no more reactor restarts in Japan this year and possibly not until mid-2013 or later depending on when the standards are put in place.
The slower reactor restarts expected in Japan, combined with slower economic growth worldwide and changes to nuclear programs in some other countries led us to re-examine our reactor forecast. For example, Canada, France and Belgium have announced plans to retire their older reactors, and India has revised its 2020 nuclear target down from 20 to 14.6 gigawatts. So while the market continues to evolve, our initial review results in an estimated 80 net new reactors over the period 2012 to 2021, compared to the 95 we expected earlier this year. Most of the decrease is due to the retirement of reactors, although some is also due to deferrals beyond 2021.
New Build Outlook – Planned Reactors (2012 to 2021)
| Region / Country | Operable | Previous Forecast | Change to | New Forecast | |||||
|---|---|---|---|---|---|---|---|---|---|
| (as of Sept 30, 2012) | New | Shut | Net New | net new | Net New | Operable 2021 | |||
| Americas 127 11 (6) 5 (1) | 4 | 131 | |||||||
| Europe 137 11 (14) (3) (3) | (6) | 131 | |||||||
| Asia 77 14 (1) 13 (8) | 5 | 82 | |||||||
| Other* 6 7 - 7 - | 7 | 13 | |||||||
| India 20 15 - 15 (3) | 12 | 32 | |||||||
| China 15 52 - 52 - | 52 | 67 | |||||||
| Russia/E. Europe** 49 17 (11) 6 - | 6 | 55 | |||||||
| Total 431 127 (32) 95 (15) | 80 | 511 |
*Other includes Iran, Pakistan, South Africa, Turkey and United Arab Emirates.
** Eastern Europe includes Armenia, Belarus and Ukraine.
Of these net new reactors, 64 are under construction today. China is the most aggressive, and we expect it to grow its nuclear power program from the 15 currently operating reactors to 67 in 2021, of which 26 are under construction.
The 80 net new reactors combined with the current base of nuclear power plants translates into a cumulative uranium demand of about 2.1 billion pounds to 2021, which is down by about 50 million pounds from our earlier forecast.
While expected demand has decreased, there has also been an increase in global supply. In China, Uzbekistan and Namibia production increased at a number of mines, which we expect will equate to about 30 million pounds of further supply over the 10-year period.
The result when we put these changes to supply and demand together is a demonstrated need for new supply of 360 million pounds from 2012 to 2021, compared to the 440 million pounds we had forecast earlier in the year.
However, the current market environment also poses challenges to bringing on new supply and could impact supply expectations as conditions continue to evolve. A number of project deferrals and cancellations have been announced as producers have reacted to lower uranium prices and general economic pressures. As well, secondary supplies continue to diminish, particularly with the end of the Russian Highly Enriched Uranium (HEU) agreement in 2013. Conclusion of this arrangement will mean the removal of 24 million pounds of relatively low-cost secondary annual uranium supply from the market, and there are no indications of a second Russian HEU deal.
Despite the changes we see to the supply/demand outlook, what remains clear is that new supply will be needed. Though some could come from additions to secondary supplies, the majority will need to come from new mines and expansions to existing mines at a time when pursuing such projects is becoming increasingly difficult. In addition, the long-term fundamentals of the industry remain strong, with 64 reactors currently under construction and some of the growth pushed further out in time. As a result, we are managing our assets through this period of uncertainty with a focus on safety, efficiency and profitable growth.
____________________
Caution about forward-looking information relating to our uranium market update
This discussion of our expectations for the nuclear industry, including its growth profile and future global uranium supply and demand and the number of reactors, is forward-looking information that is based upon the assumptions and subject to the material risks discussed under the heading Caution about forward-looking information beginning on page 17.
Outlook for 2012
Our outlook for 2012 reflects the growth expenditures necessary to help us achieve our strategy. Our outlook for consolidated capital expenditures and consolidated tax rate has changed. We explain the changes below. All other items in the table are unchanged. We do not provide an outlook for the items in the table that are marked with a dash.
See Financial results by segment on page 8 for details.
2012 Financial outlook
| Consolidated | Uranium | Fuel services | Electricity | |||
|---|---|---|---|---|---|---|
| Production | - 21.7 million lbs 13 to 14 million kgU - | |||||
| Sales volume | Sales volume | - 31 to 33 million lbs Decrease - 10% to 15% | ||||
| Capacity factor | - - - 93% | |||||
| Revenue | Decrease Decrease Decrease Increase 0% to 5% 0% to 5%1 10% to 15% 5% to 10% | |||||
| compared to 2011 | ||||||
| Average unit cost of | - Increase Increase Decrease 0% to 5%2 10% to 15% 15% to 20% | |||||
| sales (including D&A) | ||||||
| Direct administration | Increase - - - 10% to 15% | |||||
| costs compared | ||||||
| to 20113 | ||||||
| Exploration costs | - Increase - - 15% to 20% | |||||
| compared to 2011 | ||||||
| Tax rate | Recovery of 10% to 15% - - - | |||||
| Capital expenditures | $730 million4 - - $70 million |
1 Based on a uranium spot price of $42.50 (US) per pound (the Ux spot price as of October 29, 2012), a long-term price indicator of $60.00 (US) per pound (the Ux long-term indicator on September 30, 2012) and an exchange rate of $1.00 (US) for $1.00 (Cdn). 2 This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we decide to make discretionary purchases in 2012 then we expect the average unit cost of sales to increase further.
3 Direct administration costs do not include stock-based compensation expenses.
4 Does not include our share of capital expenditures at BPLP.
Our customers choose when in the year to receive deliveries of uranium and fuel services products, so our quarterly delivery patterns, and therefore our sales volumes and revenue, can vary significantly. In the fourth quarter, we expect about 40% of our 2012 deliveries to occur with an improvement in our average realized uranium price due to pricing under the mix of contracts.
We now expect a recovery of 10% to 15% for our consolidated tax rate (previously a 5% to 10% recovery). The change is primarily related to the $9 million recovery in our income tax expense that we recognized in the second quarter due to additional certainty we received on particular tax provisions.
We now expect our capital expenditures to be about $730 million compared to our previous estimate of $680 million due to changes in scope and scheduling of some of our projects in northern Saskatchewan.
Sensitivity analysis
For the rest of 2012:
- a change of $5 (US) per pound in both the Ux spot price ($42.50 (US) per pound on October 29, 2012) and the Ux long-term price indicator ($60.00 (US) per pound on September 30, 2012) would change revenue by $13 million and net earnings by $7 million
- a change of $5/MWh in the electricity spot price would change our 2012 net earnings by $1 million based on the assumption that the spot price will remain below the floor price of $51.62/MWh provided under BPLP’s agreement with the Ontario Power Authority (OPA)
- a one-cent change in the value of the Canadian dollar versus the US dollar would change revenue by $2 million and adjusted net earnings by $1 million. This sensitivity is based on an exchange rate of $1.00 (US) for $1.02 (Cdn).
Adjusted net earnings (non-IFRS measure)
Adjusted net earnings is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS measure). We use this measure as a more meaningful way to compare our financial performance from period to period. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance. Adjusted net earnings is our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting period. The adjusted earnings measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period.
Adjusted net earnings is non-standard supplemental information and should not be considered in isolation or as a substitute for financial information prepared according to accounting standards. Other companies may calculate this measure differently so you may not be able to make a direct comparison to similar measures presented by other companies.
The table below reconciles adjusted net earnings with our net earnings.
| ($ millions) | Three months | Nine months | ||||
|---|---|---|---|---|---|---|
| ended September 30 | ended September 30 | |||||
| 2012 | 2011 | 2012 | 2011 | |||
| Net earnings | 82 | 39 | 221 | 186 | ||
| Adjustments | ||||||
| Adjustments on derivatives1 (pre-tax) | (40) | 88 | (15) | 100 | ||
| Income taxes on adjustments to derivatives | 10 | (23) | 4 | (27) | ||
| Adjusted net earnings | 52 | 104 | 210 | 259 |
1 In 2008, we opted to discontinue hedge accounting for our portfolio of foreign currency forward sales contracts. Since then, we have adjusted our gains or losses on derivatives to reflect what our earnings would have been had hedge accounting been applied.
Financial results by segment
Uranium
| Highlights | Three months | Nine months | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| ended September 30 | ended September 30 | |||||||||
| 2012 | 2011 | change | 2012 | 2011 | change | |||||
| Production volume (million lbs) | 5.3 | 5.3 - | 15.4 | 15.8 (3)% | ||||||
| Sales volume (million lbs) | 5.1 | 7.2 (29)% | 18.1 | 19.1 (5)% | ||||||
| Average spot price ($US/lb) Average long-term price ($US/lb) Average realized price ($US/lb) ($Cdn/lb) | 48.08 60.67 44.49 44.99 | 51.04 (6)% 65.33 (7)% 47.33 (6)% 45.97 (2)% | 50.38 60.67 45.76 46.22 | 57.89 (13)% 68.22 (11)% 47.06 (3)% 46.36 - | ||||||
| Average unit cost of sales ($Cdn/lb UO) (including D&A) 3 8 | 28.75 | 27.59 4% | 31.47 | 29.68 6% | ||||||
| Revenue ($ millions) | 231 | 332 (30)% | 837 | 885 (5)% | ||||||
| Gross profit ($ millions) | 83 | 133 (38)% | 267 | 318 (16)% | ||||||
| Gross profit (%) | 36 | 40 (10)% | 32 | 36 (11)% |
Third quarter
Production volumes this quarter were unchanged compared to the third quarter of 2011. See Operations and development project updates starting on page 12 for more information.
Uranium revenues this quarter were down 30% compared to 2011, due to a 29% decrease in sales volumes and a 2% decrease in the $Cdn realized selling price.
Our realized prices this quarter were lower than the third quarter of 2011 mainly due to lower $US prices under fixedprice contracts. In the third quarter of 2012, our realized foreign exchange rate was $1.01, compared to $0.97 for the prior year.
Total cost of sales (including D&A) decreased by 26% ($147 million compared to $199 million in 2011). This was mainly the result of the following:
- a 29% decrease in sales volumes
- lower royalty charges ($7 million in 2012; $26 million in 2011) due to decreased deliveries of Saskatchewanproduced material
- partially offset by average unit costs for produced uranium being 16% higher due to increased non-cash production costs at our ISR locations
The net effect was a $50 million decrease in gross profit for the quarter.
First nine months
Production volumes for the first nine months of the year were lower than in the previous year due to lower output at Smith Ranch-Highland and Inkai. See Operations and development project updates starting on page 12 for more information.
For the first nine months of 2012, uranium revenues were down 5% compared to 2011, due to a 5% decrease in sales volumes.
Our $US realized prices were lower than the first nine months of 2011 mainly due to lower prices under marketrelated contracts being offset by a more favourable exchange rate. In the first nine months of 2012, our realized foreign exchange rate was $1.01 compared to $0.99 in the prior year.
Total cost of sales (including D&A) increased by 1% ($570 million compared to $567 million in 2011). This was mainly the result of the following:
- average unit costs for produced uranium were 13% higher due to increased unit production costs relating mainly to the lower production during the first nine months. We continue to expect our average unit cost of sales (including D&A) to increase by 0% to 5% for the year compared to 2011.
- royalty charges in 2012 were $2 million higher due to increased deliveries of Saskatchewan-produced material
- partially offset by a 5% decrease in sales volume
The net effect was a $51 million decrease in gross profit for the first nine months.
The following table shows the costs of produced and purchased uranium incurred in the reporting periods (non-IFRS measures see below). These costs do not include selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.
| ($Cdn/lb) | Three months | Nine months | ||||||
|---|---|---|---|---|---|---|---|---|
| ended September 30 | ended September 30 | |||||||
| 2012 | 2011 | change | 2012 | 2011 | change | |||
| Produced Cash cost Non-cash cost | 17.89 18% 7.79 11% | 18.87 12% 6.92 16% | ||||||
| 21.11 | 21.18 | |||||||
| 8.62 | 8.01 | |||||||
| Total production cost | 29.73 | 25.68 16% | 29.19 | 25.79 13% | ||||
| Quantity produced (million lbs) | 5.3 | 5.3 - | 15.4 | 15.8 (3)% | ||||
| Purchased Cash cost | 17.90 46% | 28.32 (5)% | ||||||
| 26.08 | 27.04 | |||||||
| Quantity purchased (million lbs) | 4.6 | 3.1 48% | 8.4 | 7.3 15% | ||||
| Totals Produced and purchased costs | 22.81 23% | 25.36 12% | ||||||
| 28.03 | 28.43 | |||||||
| Quantities produced and purchased (million lbs) | 9.9 | 8.4 18% | 23.8 | 23.1 3% |
Cash cost per pound, non-cash cost per pound and total cost per pound for produced and purchased uranium presented in the above table are non-IFRS measures. These measures do not have a standardized meaning or a consistent basis of calculation under IFRS. We use these measures in our assessment of the performance of our uranium business. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance and ability to generate cash flow.
These measures are non-standard supplemental information and should not be considered in isolation or as a substitute for measures of performance prepared according to accounting standards. These measures are not necessarily indicative of operating profit or cash flow from operations as determined under IFRS. Other companies may calculate these measures differently so you may not be able to make a direct comparison to similar measures presented by other companies.
To facilitate a better understanding of these measures, the following table presents a reconciliation of these measures to our unit cost of sales for the third quarters and first nine months of 2012 and 2011.
Cash and total cost per pound reconciliation
| ($ millions) | Three months | Nine months | ||||||
|---|---|---|---|---|---|---|---|---|
| ended September 30 | ended September 30 | |||||||
| 2012 | 2011 | change | 2012 | 2011 | change | |||
| Cost of product sold Add / (subtract) Royalties Standby charges Other selling costs Change in inventories | 121.8 | 164.7 (26)% (26.3) (75)% (5.2) 54% (0.6) - 17.7 608% | 480.6 | 487.5 (1)% (62.3) 3% (16.0) 31% (6.7) (57)% 102.5 57% | ||||
| (6.7) | (64.3) | |||||||
| (8.0) | (20.9) | |||||||
| (0.6) | (2.9) | |||||||
| 125.4 | 160.9 | |||||||
| Cash operating costs (a) Add / (subtract) Depreciation and amortization Change in inventories | 231.9 | 150.3 54% 34.3 (25)% 7.0 184% | 553.4 | 505.0 10% 79.1 13% 1.7 1882% | ||||
| 25.7 | 89.5 | |||||||
| 19.9 | 33.7 | |||||||
| Total operating costs (b) | 277.5 | 191.6 45% | 676.6 | 585.8 16% | ||||
| Uranium produced & purchased (millions lbs) (c) | 9.9 | 8.4 18% | 23.8 | 23.1 3% | ||||
| Cash costs per pound (a ÷ c) Total costs per pound (b ÷ c) | 23.42 | 17.89 31% 22.81 23% | 23.25 | 21.86 6% 25.36 12% | ||||
| 28.03 | 28.43 |
Please see our third quarter MD&A for updates to our uranium price sensitivity analysis.
Fuel services
(includes results for UF6, UO2 and fuel fabrication)
| Highlights | Three months | e | Nine months | ||||||
|---|---|---|---|---|---|---|---|---|---|
| ended September 30 | nded September 30 | ||||||||
| 2012 | 2011 | change | 2012 | 2011 | change | ||||
| Production volume (million kgU) | 2.1 | 2.8 (25)% | 10.9 | 11.6 (6)% | |||||
| Sales volume (million kgU) | 3.3 | 4.6 (28)% | 10.1 | 11.1 (9)% | |||||
| Realized price ($Cdn/kgU) | 16.98 | 17.42 (3)% | 17.55 | 18.04 (3)% | |||||
| Average unit cost of sales ($Cdn/kgU) (including D&A) | 16.20 | 15.34 6% | 15.32 | 15.42 (1)% | |||||
| Revenue ($ millions) | 56 | 81 (31)% | 178 | 199 (11)% | |||||
| Gross profit ($ millions) | 3 | 10 (70)% | 23 | 29 (21)% | |||||
| Gross profit (%) | 5 | 12 (58)% | 13 | 15 (13)% |
Third quarter
Production volumes in the quarter were 25% lower than in 2011 due to the reduction of planned production for 2012.
Total revenue was $25 million lower than in 2011 due to a 28% decline in deliveries of our fuel services products and a 3% decline in the realized selling price.
Our $Cdn realized price for fuel services was affected by the mix of products delivered in the quarter. In 2012, a higher proportion of fuel services sales were for UF6, which typically yields a lower price than the other fuel services products.
The total cost of sales (including D&A) decreased by 25% ($53 million compared to $71 million in 2011) due to the decrease in the sales volumes. The average unit cost of sales was 6% higher due to the mix of products delivered in the quarter.
The net effect was a decrease of $7 million in gross profit for the quarter.
First nine months
Production was 10.9 million kgU, 6% lower than the same period last year. As a result of the planned reduction in production, results will remain lower than comparable periods in 2011; production remains on track for the year.
Total revenue decreased by 11% due to a 9% decrease in sales volumes and a 3% decline in the realized selling price.
The total cost of sales (including D&A) decreased by 9% ($155 million compared to $170 million in 2011) due to the decrease in the sales volume. The average unit cost of sales was similar to the first nine months of 2011.
The net effect was a $6 million decrease in gross profit.
Electricity results
Third quarter
Total electricity revenue increased by 6% this quarter compared to the third quarter of 2011 due to higher output. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA and financial contract revenue. BPLP recognized revenue of $166 million this quarter under its agreement with the OPA, compared to $119 million in the third quarter of 2011. About 72% of BPLP’s output was sold under financial contracts this quarter compared to 53% in the third quarter of 2011. From time to time BPLP enters the market to lock in the gains under these contracts. Gains on BPLP’s contracting activity were slightly lower than in 2011.
The capacity factor was 99% this quarter, up from 93% in the third quarter of 2011 as a result of no planned outage days. Operating costs were slightly lower at $223 million compared to $232 million in 2011.
The result was a $11 million increase in our share of earnings before taxes.
BPLP distributed $95 million to the partners in the third quarter; our share was $30 million. Also, BPLP made capital calls of $17 million to the partners in the third quarter; our share was $5 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 increased 8% compared to 2011 due to higher output and higher realized prices. Realized prices reflect spot sales, revenue recognized under BPLP’s agreement with the OPA and financial contract revenue. BPLP recognized revenue of $575 million in the first nine months of 2012 under its agreement with the OPA, compared to $351 million in the first nine months of 2011. The equivalent of about 67% of BPLP’s output was sold under financial contracts in the first nine months of this year, compared to 49% in 2011. From time to time BPLP enters the market to lock in the gains under these contracts. Gains on BPLP’s contracting activity were slightly higher than in 2011.
The capacity factor was 92% for the first nine months of this year, up from 87% in the third quarter of 2011 due to a lower volume of outage days during this year’s planned outage compared to last year’s planned outage. Operating costs were lower at $668 million compared to $735 million in 2011 mainly due to lower supplemental lease payments and lower maintenance costs. These decreases were partially offset by higher fuel costs in the first nine months of 2012.
The result was a $50 million increase in our share of earnings before taxes.
BPLP distributed $285 million to the partners in the first nine months of 2012; our share was $90 million. BPLP made capital calls of $50 million to the partners in the first nine months of this year; our share was $16 million.
Operations and development project updates
Uranium – production overview
| Cameco’s share (million lbs UO) 3 8 | Three months | Nine months ended September 30 | |||||||
|---|---|---|---|---|---|---|---|---|---|
| ended September 30 | |||||||||
| 2012 | 2011 | change | 2012 | 2011 | change | ||||
| McArthur River/Key Lake | 3.8 | 3.8 - | 10.1 | 10.0 1% | |||||
| Rabbit Lake | 0.3 | 0.5 (40)% | 2.1 | 2.2 (5)% | |||||
| Smith Ranch-Highland | 0.3 | 0.3 - | 0.8 | 1.2 (33)% | |||||
| Crow Butte | 0.2 | 0.2 - | 0.6 | 0.6 - | |||||
| Inkai | 0.7 | 0.5 40% | 1.8 | 1.8 - | |||||
| Total | 5.3 | 5.3 - | 15.4 | 15.8 (3)% |
McArthur River/Key Lake
Production for the quarter and the first nine months was unchanged compared to the same periods last year. We expect our share of production this year to increase to 13.5 million pounds compared to our previous forecast of 13.1 million pounds U3O8.
Production varies from quarter to quarter depending on the sequencing of mining raises and timing of maintenance shutdowns at the mill.
At McArthur River, we have started to upgrade our electrical infrastructure to address the future need for increased ventilation and freeze capacity associated with mining new zones and increasing mine production.
At Key Lake, the new steam, oxygen and acid plants are operational. We have started projects to replace the calciner and the electrical substation.
We continue to make excellent progress in flattening the slope of the Deilmann tailings management facility pitwalls at Key Lake. The project will reduce the risk of loss of tailings capacity due to pitwall sloughing.
We are continuing to advance work on the environmental assessment for the Key Lake extension project. We have received comments from the regulators on our draft environmental impact statement and are working to address the questions and issues they have raised. We plan to submit the final environmental impact statement in 2013.
In cooperation with several uranium industry partners in Saskatchewan, we have been working on a plan with the provincial government to connect our McArthur River and Cigar Lake mine sites by completing Highway 914 in the Athabasca Basin. This crucial connection will expand access to milling infrastructure across the northern part of the province, enhance transportation efficiency and offer an alternate route in and out of northern Saskatchewan. The Government of Saskatchewan has agreed to fund half of the cost of the final road with the industry partners sharing the remaining half.
Technical report We are updating the February 2009 McArthur River technical report to reflect further advancements and changes to the McArthur River operations since that time. We plan to file the updated technical report during the fourth quarter. The highlights of the technical report are:
- a 19% increase in our share of the mineral reserves estimate from 226.2 million pounds at December 31, 2011 to 269.1 million pounds as of August 31, 2012 due to a 22% addition in tonnage and a slight decrease in the estimated average grade. See McArthur River mineral reserves and mineral resources estimates table below for more details.
- a decrease in the estimated average cash operating cost to about $19.23 per pound over the life of the mine from about $19.69 per pound estimated in 2009, despite the escalating costs in the industry. See table titled