Cameco Reports First Quarter Financial Results
SASKATOON, SASKATCHEWAN--(Marketwired - May 1, 2013)
ALL AMOUNTS ARE STATED IN CDN $ (UNLESS NOTED)
- strong first quarter production
- first quarter financial results as expected
- at Cigar Lake, continued progress towards first production in mid-2013
- completed the acquisition of NUKEM Energy GmbH
- the government of Saskatchewan announced changes to the provincial royalty system to encourage continued investment in Saskatchewan's uranium mining industry
Cameco (TSX:CCO) (NYSE:CCJ) today reported its consolidated financial and operating results for the first quarter ended March 31, 2013 in accordance with International Financial Reporting Standards (IFRS).
"Our results this quarter are consistent with what we had projected," said Tim Gitzel, president and CEO. "Deliveries from our uranium segment and revenue from Bruce Power were low, and resulted in lower net earnings.
"We remain on track with our annual outlook, and have increased our focus on streamlining and efficiency in order to remain competitive in today's uncertain environment.
"We are confident in the future growth for the industry, but also know the importance of being responsive to current market conditions by taking action today to remain a profitable, low cost producer for years to come."
| THREE MONTHS ENDED MARCH 31 |
|||||
| HIGHLIGHTS ($ MILLIONS EXCEPT WHERE INDICATED) |
2013 | 2012 | CHANGE | ||
| Revenue | 444 | 466 | (5 | )% | |
| Gross Profit | 95 | 150 | (37 | )% | |
| Net earnings attributable to equity holders | 9 | 129 | (93 | )% | |
| $ per common share (diluted) | 0.02 | 0.33 | (94 | )% | |
| Adjusted net earnings (see non-IFRS) | 27 | 121 | (78 | )% | |
| $ per common share (adjusted and diluted) | 0.07 | 0.31 | (77 | )% | |
| Cash provided by operations (after working capital changes) | 269 | 374 | (28 | )% | |
FIRST QUARTER
Net earnings attributable to equity holders (net earnings) this quarter were $9 million ($0.02 per share diluted) compared to $129 million ($0.33 per share diluted) in the first quarter of 2012. In addition to the items noted below, net earnings were impacted by mark-to-market losses on foreign exchange derivatives.
On an adjusted basis, our earnings this quarter were $27 million ($0.07 per share diluted) compared to $121 million ($0.31 per share diluted) (see non-IFRS measure) in the first quarter of 2012, mainly due to:
- lower earnings from our uranium segment based on lower sales volumes and lower realized prices
- lower earnings from our electricity segment based on lower generation and higher operating costs
- higher expenditures for administration due to the addition of NUKEM's administration and advisory fee, and costs for corporate restructuring as described in our first quarter MD&A
See Financial results by segment for more detailed discussion.
Uranium market update
Since the previous quarter, the uranium market has seen little change. Near to medium-term uncertainty continues to impede a recovery, with neither buyers nor suppliers seeming to feel much pressure to contract. Most suppliers have significant commitments out to 2016, and utilities are well covered for a similar period. As a result, over this quarter, volumes contracted have remained low, and uranium prices have been relatively stable.
As we have noted in previous quarters, we believe the market will remain in this 'wait-and-see' mode until catalyzed by events such as reactor restarts in Japan and a significant return to long-term contracting by utilities. We expect to see both of these catalysts realized, though the timing remains unclear. In our view, utilities are beginning to move into the window of time during which they would normally begin contracting for requirements in 2016, and, as the regulatory process is worked through in Japan, we believe reactors will be restarted in 2013. The process began in January, when the Nuclear Regulatory Authority (NRA) issued draft safety guidelines outlining the proposed requirements for restart. The guidelines have now been released for public comment, with the final guidelines expected in July. We are in frequent contact with our Japanese utility customers and understand that they are investing significantly to prepare their nuclear assets to meet the requirements for restart.
While we watch to see how the near term will evolve, we believe the long-term picture for nuclear continues to be strong. Our current estimates project nuclear generating capacity will reach about 510 gigawatts by 2022 from today's 392 gigawatts, which represents average annual growth of 3%. Of this expected growth, approximately 65 new reactors (65 gigawatts of generating capacity) are under construction today. Much of this growth is coming from India and China, which together plan to bring eight new reactors online this year. Canada recently finalized the details of the Nuclear Cooperation Agreements with both countries, enabling Canada, and Cameco, to take part in the opportunity these countries represent to the nuclear industry by allowing deliveries of Canadian material.
The other side of the equation is supply, which faces challenges both from primary and secondary sources. Secondary sources, which have historically kept supply in balance with demand, continue to diminish, particularly with the end of the Russian Highly Enriched Uranium commercial agreement this year. The end of this agreement will remove more pounds from the market than our total annual production, and there is no secondary source of similar scale expected. But future primary supply is also starting to suffer as a number of projects were cancelled or deferred in 2012 while the uranium spot price remained at a level well below that required to incentivize new projects. This primary supply uncertainty comes at a time when demand growth is on the horizon. However, the reduction in future primary supply does not directly impact the near-term market and there are indications that some supply projects, primarily driven by sovereign interests, may proceed despite market conditions.
Despite the current challenging industry environment, we are well positioned to continue to succeed. We have advantages like extensive mineral reserves and resources, low cost operations, a strong sales contract portfolio, experienced employees and a growth strategy that will allow us to remain competitive in challenging environments, while maintaining the ability to respond quickly with additional production when the market signals that more supply is required.
Outlook for 2013
Our outlook for 2013 reflects the growth expenditures necessary to help us achieve our strategy. Our consolidated outlook for revenue and direct administration costs have increased due to the inclusion of NUKEM. Our outlook for sales volumes from our fuel services segment has also changed and we explain the change below. We do not provide an outlook for the items in the table that are marked with a dash.
See Financial results by segment for details.
2013 FINANCIAL OUTLOOK
NUKEM is included in the consolidated amounts and our outlook for the NUKEM segment has been added to the table below. Starting this quarter, IFRS 11 - Joint Arrangements requires that we account for our interest in BPLP using equity accounting. BPLP is not included in consolidated amounts due to the change in accounting.
| CONSOLIDATED | URANIUM | FUEL SERVICES | NUKEM | ELECTRICITY | ||||||
| Production | - | 23.3 million lbs | 15 to 16 million kgU | - | - | |||||
| Sales volume | - | 31 to 33 million lbs | Increase 5% to 10% |
9 to 11 million lbs U3O8, 0.5 million SWU | - | |||||
| Capacity factor | - | - | - | - | 88% | |||||
| Revenue compared to 2012 | Increase 25% to 30% |
Increase 0% to 5%1 |
Increase 5% to 10% |
$500 to $600 million | Decrease 5% to 10% |
|||||
| NUKEM Operating cash flows | - | - | - | $100 to $125 million | - | |||||
| NUKEM gross profit | - | - | - | 3% to 5% | - | |||||
| Average unit cost of sales (including D&A) |
- | Increase 0% to 5%2 |
Decrease 0% to 5% |
- | Increase 25% to 30% |
|||||
| Direct administration costs compared to 20123 | Increase 0% to 5% |
- | - | $10 to 12 million | - | |||||
| Exploration costs compared to 2012 | - | Decrease 5% to 10% |
- | - | - | |||||
| Tax rate | Recovery of 15% to 20% |
- | - | Expense of 30% to 35% | - | |||||
| Capital expenditures | $655 million4 | - | - | - | $93 million (our share) |
| 1 | Based on a uranium spot price of $40.50 (US) per pound (the Ux spot price as of April 29, 2013), a long-term price indicator of $57.00 (US) per pound (the Ux long-term indicator on April 29, 2013) 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 2013 then we expect the overall unit cost of product sold 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. |
We now expect an increase of 5% to 10% for sales volumes in our fuel services segment (previously an increase of up to 5%), due to increased fuel services production (15 to 16 million KgU compared to 13 to 14 million KgU in 2012) and increased sales commitments in 2013.
In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns, sales volumes and revenue, can vary significantly. We expect our uranium deliveries for the second quarter will be greater than the first quarter. Uranium sales for the balance of 2013 are expected to be more heavily weighted (about 60%) to the second half of the year. However, not all delivery notices have been received to date, which could alter the delivery pattern. Typically, we receive notices six months in advance of the requested delivery date.
SENSITIVITY ANALYSIS
For the rest of 2013:
- a change of $5 (US) per pound in both the Ux spot price ($40.50 (US) per pound on April 29, 2013) and the Ux long-term price indicator ($57.00 (US) per pound on April 29, 2013) would change revenue by $56 million and net earnings by $30 million
- a change of $5/MWh in the electricity spot price would change our 2013 net earnings by $1 million based on the assumption that the spot price will remain below the floor price of $52.34/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 $9 million and adjusted net earnings by $5 million, with a decrease in the value of the Canadian dollar versus the US dollar having a positive impact. This sensitivity is based on an exchange rate of $1.00 (US) for $1.00 (Cdn).
ADJUSTED NET EARNINGS (NON-IFRS MEASURE)
Adjusted net earnings is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS measure). We use this measure as a more meaningful way to compare our financial performance from period to period. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance. Adjusted net earnings is our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting period. The adjusted earnings measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period, and has been adjusted for impairment charges on non-producing properties.
Adjusted net earnings is non-standard supplemental information and should not be considered in isolation or as a substitute for financial information prepared according to accounting standards. Other companies may calculate this measure differently, so you may not be able to make a direct comparison to similar measures presented by other companies.
The table below reconciles adjusted net earnings with our net earnings.
| THREE MONTHS ENDED MARCH 31 |
|||||
| ($ MILLIONS) | 2013 | 2012 | |||
| Net earnings attributable to equity holders | 9 | 129 | |||
| Adjustments | |||||
| Adjustments on derivatives1(pre-tax) | 25 | (11 | ) | ||
| Income taxes on adjustments to derivatives | (7 | ) | 3 | ||
| Adjusted net earnings | 27 | 121 | |||
| 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. |
CRA Disclosure
Since 2008, the Canada Revenue Agency (CRA) has disputed the offshore marketing company structure and related transfer pricing methodology we used for certain intercompany uranium sale and purchase agreements, and issued notices of reassessment for our 2003 through 2007 tax returns. We believe the ultimate resolution of this matter will not be material to our financial position, results of operations and cash flows in the year(s) of resolution.
There have been no fact changes in this case since we first disclosed it in 2008. However, in 2013, we were required to report separately the cash payment to CRA of approximately $27 million for taxes, interest and instalment penalties. Until 2013, we had not been required to make any significant cash tax payments due to the availability of elective deductions and tax loss carryovers. However, we were required to make small cash payments for interest and instalment penalties, which totaled about $13 million. These amounts were not reported separately as they were not material in any given year. Transfer pricing is a complex area of tax law, and it is difficult to predict the outcome of a case like ours as there are only a handful of reported court decisions on transfer pricing in Canada. However, tax authorities generally test two things:
- the governance (structure)
- the price
As the majority of our customers are located outside Canada, we established an offshore marketing subsidiary. For this subsidiary to be able to enter into sales agreements, it must be backed up by a supply of uranium, which is made possible by our intercompany purchase and sales agreements as well as uranium supply agreements with third parties. We have arm's-length transfer price arrangements in place, which expose both parties to the risks and the rewards accruing to it under this portfolio of purchase and sales contracts.
With respect to the contract prices, they are generally comparable to those established in sales contracts between arm's-length buyers and sellers at the time. Based on an analysis of our contract portfolio and other contracts entered into at the time, we have recorded a cumulative tax provision of $65 million, where an argument could be made that our transfer price may have fallen outside of an appropriate range of pricing in uranium contracts for the period from 2003 to March 31, 2013.
We are confident that we will be successful in our case; however, the Canadian Income Tax Act includes provisions that require certain companies to pay 50% of the cash tax plus related interest and instalment penalties at the time of reassessment. For the years 2003 through 2007, the CRA issued notices of reassessment for approximately $1.3 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $380 million. Once elective deductions and tax loss carryovers were applied to the amounts reassessed in 2012, as well as interest and instalment penalties, the resulting amount payable was approximately $54 million, 50% of which, or $27 million, we remitted in 2013. Adding the $13 million remitted in previous years brings the total cash paid to CRA to $40 million. No transfer pricing penalties have been assessed.
Using the methodology we believe the CRA will continue to apply, and including the $1.3 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $4.9 billion in income as taxable in Canada for the years 2003 through 2012, which would result in a related tax expense of approximately $1.4 billion. Cash taxes payable would be between $800 million and $850 million. In addition, we estimate there would be interest and instalment penalties applied that would be material to Cameco. We would be responsible for remitting 50% of the cash taxes, or between $400 million and $425 million, plus related interest and instalment penalties assessed, which would be material to Cameco.
Under the Canadian Tax Act, the amount required to be remitted each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers; however, we expect it will generally follow the schedule in the table below.
| MARCH 31, 2013 ($ MILLIONS) | 2003 - 2013 | 2014 - 2016 | 2017 - 2023 | TOTAL |
| 50% of cash taxes payable in the period1 | 18 | 50 - 75 | 325 - 350 | 400 - 425 |
| 1 | These amounts do not include interest and instalment penalties, which totaled approximately $22 million to March 31, 2013. |
In light of our view of the likely outcome of the case as described above, we expect to recover the amounts remitted to CRA, including the $40 million already paid.
The case on the 2003 reassessment is expected to go to trial in the fall of 2014. If this timing is adhered to, we expect to have a Tax Court decision in 2015.
Caution about forward-looking information relating to our CRA tax dispute
This discussion of our expectations relating to our tax dispute with CRA and future tax reassessments by CRA, including the amounts of future additional taxable income, additional tax expense, cash taxes payable and interest and possible penalties thereon and related remittances, and timing of a Tax Court decision, 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 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.
Assumptions
- the CRA will reassess us for the years 2008 through 2012 using a similar methodology as for the years 2003 through 2007, with the time lag for the reassessments for each year being similar to what has occurred to date
- we will be able to apply elective deductions and tax loss carryovers to the extent anticipated
- the CRA will not seek to impose transfer pricing penalties in addition to interest charges and instalment penalties
- we will be substantially successful in our dispute with the CRA and the cumulative tax provision of $65 million to date will be adequate to satisfy any tax liability resulting from the outcome of the dispute to date.
Material risks that could cause actual results to differ materially
- the CRA reassesses us for years 2008 through 2012 using a different methodology than for years 2003 through 2007, or we are unable to utilize elective deductions and loss carryovers to the same extent as anticipated, resulting in the required cash payments to CRA pending the outcome of the dispute being higher than expected
- the time lag for the reassessments for each year is different than for those to date
- the CRA may seek to impose transfer pricing penalties
- we are unsuccessful and the outcome of our dispute with CRA results in significantly higher cash taxes, interest charges and penalties than the amount of our cumulative tax provision, which could have a material adverse effect on our liquidity, financial position, results of operations and cash flows
- cash tax payable increases due to unanticipated adjustments by CRA not related to transfer pricing
| Financial results by segment |
| Uranium |
| THREE MONTHS ENDED MARCH 31 |
|||||
| HIGHLIGHTS | 2013 | 2012 | CHANGE | ||
| Production volume (million lbs) | 5.9 | 4.8 | 23 | % | |
| Sales volume (million lbs) | 5.1 | 8.2 | (38 | )% | |
| Average spot price ($US/lb) | 42.71 | 51.73 | (17 | )% | |
| Average long-term price ($US/lb) | 56.50 | 60.33 | (6 | )% | |
| Average realized price | |||||
| ($US/lb) | 48.42 | 48.69 | (1 | )% | |
| ($Cdn/lb) | 48.25 | 49.32 | (2 | )% | |
| Average unit cost of sales ($Cdn/lb) (including D&A) | 31.90 | 31.99 | - | ||
| Revenue ($ millions) | 247 | 406 | (39 | )% | |
| Gross profit ($ millions) | 84 | 143 | (41 | )% | |
| Gross profit (%) | 34 | 35 | (3 | )% | |
FIRST QUARTER
Production volumes this quarter were 23% higher compared to the first quarter of 2012, due mainly to higher production at McArthur River/Key Lake and Inkai. See Operations and development project updates for more information.
Uranium revenues were down 39% due to a 38% decrease in sales volumes and a 2% decrease in the Canadian dollar average realized price.
Our realized prices this quarter were lower than the first quarter of 2012, mainly due to lower US dollar prices under market related contracts. In the first quarter of 2013, the uranium spot price averaged $42.71 (US), 17% lower than the $51.73 (US) in the first quarter of 2012.
Total cost of sales (including D&A) decreased by 38% ($163 million compared to $263 million in 2012). This was mainly the result of a 38% decrease in sales volumes, and lower royalty charges due to the slightly lower realized price and reduced deliveries of Saskatchewan-produced material. In the first quarter of 2013, total royalty charges were $14 million compared to $33 million in the first quarter of 2012.
The net effect was a $59 million decrease in gross profit for the quarter.
The table below shows the costs of produced and purchased uranium incurred in the reporting periods (which are non-IFRS measures, see the paragraphs below the table). These costs do not include selling costs such as royalties, transportation and commissions, nor do they reflect the impact of opening inventories on our reported cost of sales.
| THREE MONTHS ENDED MARCH 31 |
|||||
| ($CDN/LB) | 2013 | 2012 | CHANGE | ||
| Produced | |||||
| Cash cost | 19.12 | 22.39 | (15 | )% | |
| Non-cash cost | 8.44 | 7.51 | 12 | % | |
| Total production cost | 27.56 | 29.90 | (8 | )% | |
| Quantity produced (million lbs) | 5.9 | 4.8 | 23 | % | |
| Purchased | |||||
| Cash cost | 33.44 | 34.64 | (3 | )% | |
| Quantity purchased (million lbs) | 2.3 | 1.4 | 64 | % | |
| Totals | |||||
| Produced and purchased costs | 29.21 | 30.97 | (6 | )% | |
| Quantities produced and purchased (million lbs) | 8.2 | 6.2 | 32 | % | |
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 first quarters of 2013 and 2012.
| CASH AND TOTAL COST PER POUND RECONCILIATION |
| THREE MONTHS ENDED MARCH 31 |
|||||||
| ($ MILLIONS) | 2013 | 2012 | CHANGE | ||||
| Cost of product sold | 144.0 | 231.1 | (38 | )% | |||
| Add / (subtract) | |||||||
| Royalties | (14.4 | ) | (33.4 | ) | (57 | )% | |
| Standby charges | (8.1 | ) | (7.1 | ) | 14 | % | |
| Other selling costs | 2.8 | (1.9 | ) | (247 | )% | ||
| Change in inventories | 65.4 | (32.7 | ) | (300 | )% | ||
| Cash operating costs (a) | 189.7 | 156.0 | 22 | % | |||
| Add / (subtract) | |||||||
| Depreciation and amortization | 19.5 | 31.9 | (39 | )% | |||
| Change in inventories | 30.3 | 4.1 | 639 | % | |||
| Total operating costs (b) | 239.5 | 192.0 | 25 | % | |||
| Uranium produced & purchased (millions lbs) (c) | 8.2 | 6.2 | 32 | % | |||
| Cash costs per pound (a ÷ c) | 23.14 | 25.16 | (8 | )% | |||
| Total costs per pound (b ÷ c) | 29.21 | 30.97 | (6 | )% | |||
ROYALTIES
The government of Saskatchewan has recently approved changes to both the basic and tiered royalty systems for uranium as described below.
The basic royalty is equal to 5% of gross sales of Saskatchewan uranium (gross sales) and is reduced by the Saskatchewan resource credit (SRC), which, effective April 1, 2013, is equal to 0.75% of gross sales. Prior to the changes approved by the government on March 20, 2013, the SRC was equal to 1% of gross sales.
The government has also changed tiered royalties from a revenue-based system to a modified profit-based system retroactive to January 1, 2013. Under the new system, a 10% tiered royalty will be charged on profit up to $22/kg U3O8 ($9.98/lb) and a 15% tiered royalty will be charged on profit in excess of $22/kg U3O8. Profit will be determined as gross sales less certain operating costs, exploration costs and actual capital costs. Costs will be deductible as incurred at the discretion of the producer, subject to transitional rules.
The overall structure is expected to be positive over the next 15 years, although the magnitude of the impact will not be known until the provincial regulations are finalized. The exact timing of this step will not impact the date the new tiered royalty system takes effect.
In addition, as a resource corporation in Saskatchewan, we pay a corporate resource surcharge equal to 3% of gross sales.
| Fuel services |
| (includes results for UF6, UO2 and fuel fabrication) |
| THREE MONTHS ENDED MARCH 31 |
||||
| HIGHLIGHTS | 2013 | 2012 | CHANGE | |
| Production volume (million kgU) | 4.7 | 4.5 | 4 | % |
| Sales volume (million kgU) | 3.4 | 2.9 | 17 | % |
| Average realized price ($Cdn/kgU) | 19.60 | 20.57 | (5 | )% |
| Average unit cost of sales ($Cdn/kgU) (including D&A) | 16.27 | 16.65 | (2 | )% |
| Revenue ($ millions) | 66 | 60 | 10 | % |
| Gross profit ($ millions) | 11 | 11 | - | |
| Gross profit (%) | 17 | 18 | (6 | )% |
FIRST QUARTER
Total revenue increased by 10% due to a 17% increase in sales volumes, offset by a 5% decrease in realized price.
The total cost of products and services sold (including D&A) increased by 15% ($55 million compared to $48 million in the first quarter of 2012) due to the increase in sales volumes, offset by a decrease in the average unit cost of sales. When compared to 2012, the average unit cost of sales was 2% lower due to the mix of fuel services products sold.
The net effect was no change in gross profit.
| NUKEM |
| THREE MONTHS ENDED MARCH 31 |
|||||
| ($ MILLIONS EXCEPT WHERE INDICATED) | NUKEM | PURCHASE ACCOUNTING | CONSOLIDATED | ||
| Uranium sales (million lbs) | 2.3 | - | 2.3 | ||
| Conversion sales (million kgU) | 0.3 | - | 0.3 | ||
| Revenue | 132 | (1 | ) | 131 | |
| Cost of product sold (including D&A) | 103 | 24 | 127 | ||
| Gross profit | 29 | (25 | ) | 4 | |
| Net earnings | 14 | (17 | ) | (3 | ) |
| Adjustments on derivatives1 | 2 | - | 2 | ||
| Adjusted net earnings1 | 16 | (17 | ) | (1 | ) |
| Cash provided by operations | 99 | - | 99 | ||
| 1 | Adjustments relate to unrealized gains and losses on foreign currency forward sales contracts (see non-IFRS) |
On January 9, 2013, we completed the acquisition of NUKEM Energy GmbH (NUKEM) from Advent International (Advent) and other shareholders. NUKEM is one of the world's leading traders and brokers of nuclear fuel products and services.
NUKEM was acquired for cash consideration of EUR107 million ($140 million (US)). We also assumed NUKEM's net debt which amounted to about EUR79 million ($104 million (US)) on January 9, 2013. Acquisition related costs of $4 million (2012) and an advisory fee of $3 million (2013) have been expensed and included in administration expense in the consolidated statement of earnings. We received the economic benefits of owning NUKEM as of January 1, 2012; however, in accordance with accounting requirements, our financial reporting will reflect results from January 9, 2013 forward.
The purchase agreement also includes an earn-out provision that could provide Advent with a share of NUKEM's earnings under certain conditions for the years 2012 through 2014. The earn-out is based on NUKEM exceeding certain minimum threshold levels of earnings before interest, taxes, depreciation and amortization (EBITDA), as specified and defined in the purchase agreement. The EBITDA is derived from NUKEM's audited financial statements. For 2012, the earn-out amount was $8 million (US) as EBITDA for the year exceeded the payout threshold of $115 million (US). If payable, the next earn-out payment will be made in 2015.
For accounting purposes, the purchase price is allocated to the assets and liabilities acquired based on their fair values as of the acquisition date. The purchase price allocation is provided in the table below. We believe that these values are representative of the transaction; however, it is possible that the final allocation will differ.
Much of the purchase price was related to nuclear fuel inventories and the portfolio of sales and purchase contracts acquired. The amounts attributed to inventory and contracts were based on market values as at the acquisition date. They will be charged to earnings in the period(s) in which related transactions occur. The amount categorized as goodwill reflects the value assigned to the expected future earnings capabilities of the organization. This is the earnings potential that we anticipate will be realized through new business arrangements. Goodwill is not amortized and is tested for impairment at least annually.
| PURCHASE PRICE ALLOCATION |
| $US MILLIONS | |||
| Net assets | |||
| Working capital | (22 | ) | |
| Inventory | 165 | ||
| Sales, purchase contracts and other intangibles | 88 | ||
| Goodwill | 88 | ||
| Debt | (117 | ) | |
| Deferred taxes | (54 | ) | |
| Net assets acquired | 148 | ||
| Financed by | |||
| Cash | 140 | ||
| Additional consideration (earn-out provision) | 8 | ||
| Liabilities and equity | 148 | ||
FIRST QUARTER
During the first three months of 2013, NUKEM delivered 2.3 million pounds of uranium and 0.3 million kgU of conversion services. On a consolidated basis, NUKEM contributed $131 million in revenues, $4 million in gross profit and an adjusted net loss (see non-IFRS measure) of $1 million as administrative and financing charges more than offset gross profits in the quarter. NUKEM's contribution to our earnings is significantly impacted by our purchase price accounting. Excluding the impact of the purchase accounting, NUKEM's adjusted net earnings (see non-IFRS measure) were $16 million for the quarter. NUKEM generated strong cash flows of $99 million from its operating activities during the first quarter due largely to a drawdown of inventory and the collection of accounts receivable.
As noted above, much of the NUKEM purchase price was attributable to inventories and the portfolio of contracts. With respect to nuclear fuel inventories, amounts assigned were based on market values as of the date of acquisition. As these quantities are delivered to NUKEM's customers, we will adjust the cost of product sold to reflect the values at the acquisition date, regardless of NUKEM's historic costs.
As of the date of the purchase agreement, had NUKEM's sales and purchase contracts been settled, it would have realized significant financial benefit and as a result, we paid a premium to acquire the portfolio. Accordingly, a portion of the purchase price has been attributed to the various contracts. In our accounting for NUKEM, we will amortize the amounts assigned to the portfolio in the periods in which NUKEM transacts under the relevant contracts. The net effect is a reduction in reported profit margins relative to NUKEM's results. We expect the majority of the amount allocated to the contract portfolio will be amortized within two years.
Electricity results
FIRST QUARTER
Total electricity revenue decreased 14% this quarter due to lower output and lower realized price. Realized prices reflect spot sales, revenue recognized under BPLP's agreement with the OPA, and financial contract revenue. BPLP recognized revenue of $124 million this quarter under its agreement with the OPA, compared to $185 million in the first quarter of 2012. The equivalent of about 77% of BPLP's output was sold under financial contracts this quarter, compared to 62% in the first quarter of 2012. From time to time, BPLP enters the market to lock in gains under these contracts. Gains on BPLP's contract activity in the first quarter of 2013 were lower than the same period in 2012.
The capacity factor was 78% this quarter, down from 85% in the first quarter of 2012. There were 70 planned and nine unplanned outage days in the quarter, compared to 46 planned and five unplanned outage days in the first quarter of 2012.
Operating costs were $283 million compared to $255 million in 2012 due to higher maintenance costs incurred primarily as a result of more planned outage days in the first quarter.
The result was a $1 million loss before taxes in the first quarter of 2013 compared to $79 million in earnings before taxes in the first quarter of 2012.
BPLP distributed $100 million to the partners in the first quarter. Our share was $32 million. BPLP capital calls to the partners in the first quarter were $7 million. Our share was $2 million. The partners have agreed that BPLP will distribute excess cash monthly, and will make separate cash calls for major capital projects.
FLOOR PRICE AGREEMENT EXTENSION
Bruce Power and the OPA reached an agreement to amend the Bruce Power Refurbishment Implementation Agreement to extend the floor price from the original Bruce B unit end of life dates between 2016 and 2019, to between 2019 and 2020. It does not change the price of the Bruce B floor.
Operations and development project updates
Production in our uranium segment this quarter was 1.1 million pounds higher than the first quarter of 2012.
| URANIUM PRODUCTION |
| THREE MONTHS ENDED MARCH 31 |
||||
| CAMECO'S SHARE (MILLION LBS) |
2013 | 2012 | CHANGE | |
| McArthur River/Key Lake | 3.5 | 2.9 | 21 | % |
| Rabbit Lake | 1.1 | 1.0 | 10 | % |
| Smith Ranch-Highland | 0.3 | 0.2 | 50 | % |
| Crow Butte | 0.2 | 0.2 | - | |
| Inkai | 0.8 | 0.5 | 60 | % |
| Total | 5.9 | 4.8 | 23 | % |
McArthur River/Key Lake
Production for the quarter was 21% higher compared to the same period last year due to the timing of the annual maintenance shutdown. The mill will be shut down for three weeks in May to complete planned work. We expect our share of production this year will be 13.2 million pounds U3O8.
We are continuing to advance the underground exploration drifts to the southwest and northeast directions and will focus on developing zone 4 and areas at the south end of the underground mine workings.
We are continuing to advance work on the environmental assessment for the Key Lake extension project. We plan to submit the final environmental impact statement for review by the provincial and federal regulators and pursue the required regulatory approvals in 2013.
Rabbit Lake
Production remains on track for the year. To ensure the most efficient operation of the mill throughout the year, we continually manage ore supply and, therefore, experience large variations in mill production from quarter to quarter.
Smith Ranch-Highland and Crow Butte
At our US operations, production for the quarter was slightly higher than the first quarter of 2012.
Our ability to bring new wellfields into production in both Wyoming and Nebraska continues to be affected by the lengthened review process to obtain regulatory approvals. The operating environment is becoming more complex as public interest and regulatory oversight increase.
At Smith Ranch-Highland, we are finishing construction of the satellite plant and the first wellfields at North Butte, with production expected to begin in the second quarter. North Butte is expected to contribute approximately 300,000 pounds in 2013 and rampup to a target annual production rate of more than 700,000 pounds per year by 2015.
Inkai
Production was 60% higher for the quarter compared to the same period last year. We have continued to bring on new wellfields to maintain a higher head grade in the wellfield production mix, which has resulted in the higher first quarter production. The higher head grade and other improvements to the extraction processes allow the Inkai operation to produce at its design capacity of 5.2 million pounds per year.
Cigar Lake
We continued to make solid progress at Cigar Lake in the first quarter and expect commissioning in ore in mid-2013, with the first packaged pounds in the fourth quarter.
During the quarter, the first jet boring unit completed a successful test program in waste rock. The second jet boring unit is expected to be shipped to site and moved underground in the second quarter.
Installation of the underground and surface infrastructure required to begin commissioning in ore in mid-2013 is ongoing and progressing well.
Cigar Lake's licence from the Canadian Nuclear Safety Commission (CNSC) expires at the end of 2013. The current licence allows for various mine construction activities as well as mining of ore for commissioning purposes. We made an application to the CNSC in 2012 to amend the current licence, ahead of its expiry date. The application included a request for a ten-year term. The CNSC held a public hearing on April 3, 2013. We expect a decision during the second quarter and anticipate that Cigar Lake will have the full operating licence in mid-2013.
Fuel services
Fuel services produced 4.7 million kgU in the first quarter, 4% higher than the same period last year. We increased our production target in 2013 to between 15 million and 16 million kgU, so quarterly production is anticipated to be higher than comparable periods in 2012.
The current collective agreements with unionized employees at the Port Hope conversion facility will expire on June 30, 2013. Bargaining began in April 2013. There is risk to production if we are unable to reach an agreement and a work stoppage occurs.
Qualified persons
The technical and scientific information discussed in this document for our material properties (McArthur River/Key Lake, Inkai and Cigar Lake) was approved by 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
| Cigar Lake |
- Grant Goddard, vice-president, Saskatchewan mining north, Cameco
| Inkai |
- Alain G. Mainville, director, mineral resources management, Cameco
CAUTION ABOUT FORWARD-LOOKING INFORMATION
This document 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 document as forward-looking information.
Key things to understand about the forward-looking information in this document:
- It typically includes words and phrases about the future, such as: anticipate, believe, estimate, expect, plan, will, goal, target, forecast, project, strategy and outlook (see examples below).
- It represents our current views, and can change significantly.
- It is based on a number of material assumptions, including those we have 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 and first quarter MD&A, which include a discussion of other material risks that could cause actual results to differ significantly from our current expectations.
- Forward-looking information is designed to help you understand management's current views of our near and longer term prospects, and it may not be appropriate for other purposes. We will not necessarily update this information unless we are required to by securities laws.
Examples of forward-looking information in this document
- our expectations about 2013 and future global uranium supply, consumption, demand, and nuclear generating capacity, including the discussion under the heading Uranium market update
- the outlook for each of our operating segments for 2013, and our consolidated outlook for the year
- our expectations about changes to Saskatchewan uranium royalty systems
- our expectations relating to our tax dispute with Canada Revenue Agency (CRA) and future tax reassessments by CRA
- our future plans for each of our uranium operating properties and development project
- our expectations regarding Cigar Lake
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, or we are unsuccessful in our dispute with the CRA
- our production costs are higher than planned, or necessary supplies are not available, or not available on commercially reasonable terms
- our estimates of production, purchases, costs, decommissioning or reclamation expenses, or our tax expense estimates, prove to be inaccurate
- we are unable to enforce our legal rights under our existing agreements, permits or licences, or are subject to litigation or arbitration that has an adverse outcome
- there are defects in, or challenges to, title to our properties
- our mineral reserve and resource estimates are not reliable, 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
- 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, civil unrest, social or political activism, accident or a deterioration in political support for, or demand for, nuclear energy
- we are impacted by changes in the regulation or public perception of the safety of nuclear power plants, which adversely affect the construction of new plants, the relicensing of existing plants and the demand for uranium
- there are changes to government regulations or policies that adversely affect us, including tax and trade laws and policies
- our uranium and conversion suppliers fail to fulfill delivery commitments
- our Cigar Lake development, mining or production plans are delayed or do not succeed, including as a result of any difficulties encountered with the jet boring mining method or our inability to acquire any of the required jet boring equipment
- our McArthur River development, mining or production plans are delayed or do not succeed
- 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, equipment failure, lack of tailings capacity, labour shortages, labour relations issues (including an inability to renew agreements with unionized employees at McArthur River, Key Lake or the Port Hope conversion facility), strikes or lockouts, underground floods, cave ins, ground movements, tailings dam failures, transportation disruptions or accidents, or other development and operating risks
- NUKEM's actual uranium sales volume, cash flows and revenue in 2013 and in the future are lower than expected due to losses in connection with spot market purchases, counterparty default on payment or other obligations, counterparty insolvency or other risks
- departure of key personnel at NUKEM could have an adverse effect on continuing operations
Material assumptions
- our expectations regarding sales and purchase volumes and prices for uranium, fuel services and electricity
- our expectations regarding the demand for uranium, the construction of new nuclear power plants and the relicensing of existing nuclear power plants not being more adversely affected than expected by changes in regulation or in the public perception of the safety of nuclear power plants
- our expected production level and production costs
- the assumptions regarding market conditions upon which we have based our capital expenditure expectations
- our expectations regarding spot prices and realized prices for uranium
- our expectations regarding tax rates and payments, the outcome of the dispute with the CRA, foreign currency exchange rates and interest rates
- our decommissioning and reclamation expenses
- our mineral reserve and resource estimates, and the assumptions upon which they are based, are reliable
- the geological, hydrological and other conditions at our mines
- the success of our Cigar Lake development, mining and production plans, including the success of the jet boring mining method at Cigar Lake and that we will be able to obtain the additional jet boring systems we require on schedule
- the success of our McArthur River development, mining and production plans
- our ability to continue to supply our products and services in the expected quantities and at the expected times
- our ability to comply with current and future environmental, safety and other regulatory requirements, and to obtain and maintain required regulatory approvals
- our operations are not significantly disrupted as a result of political instability, nationalization, terrorism, sabotage, blockades, civil unrest, breakdown, natural disasters, governmental or political actions, litigation or arbitration proceedings, the unavailability of reagents, equipment, operating parts and supplies critical to production, labour shortages, labour relations issues (including an inability to renew agreements with unionized employees at McArthur River, Key Lake or the Port Hope conversion facility), strikes or lockouts, underground floods, cave ins, ground movements, tailings dam failure, lack of tailings capacity, transportation disruptions or accidents or other development or operating risks
- NUKEM's actual uranium sales volume, cash flows and revenue in 2013 and in the future will be consistent with our expectations
- key personnel will remain with NUKEM
Quarterly dividend notice
We announced today that our board of directors approved a quarterly dividend of $0.10 per share on the outstanding common shares of the corporation that is payable on July 15, 2013, to shareholders of record at the close of business on June 28, 2013.
Conference call
We invite you to join our first quarter conference call on Wednesday May 1, 2013 at 1:00 p.m. Eastern.
The call will be open to all investors and the media. To join the call, please dial (866) 240-9772 (Canada and US) or (416) 340-8530. An operator will put your call through. A live audio feed of the conference call will be available from a link at cameco.com. See the link on our home page on the day of the call.
A recorded version of the proceedings will be available:
- on our website, cameco.com, shortly after the call
- on post view until midnight, Eastern, June 1, 2013
by calling (800) 408-3053 or (905) 694-9451 (Passcode 7039949#)
Additional information
You can find a copy of our first quarter MD&A and interim financial statements on our website at cameco.com, on SEDAR at sedar.com and on EDGAR at sec.gov/edgar.shtml.
Additional information, including our 2012 annual management's discussion and analysis, annual audited financial statements and annual information form, is available on SEDAR at sedar.com, on EDGAR at sec.gov/edgar.shtml and on our website at cameco.com.
Profile
We are one of the world's largest uranium producers, a significant supplier of conversion services and one of two Candu fuel manufacturers in Canada. Our competitive position is based on our controlling ownership of the world's largest high-grade reserves and low-cost operations. Our uranium products are used to generate clean electricity in nuclear power plants around the world, including Ontario where we are a limited partner in North America's largest nuclear electricity generating facility. We also explore for uranium in the Americas, Australia and Asia. Our shares trade on the Toronto and New York stock exchanges. Our head office is in Saskatoon, Saskatchewan.
As used in this news release, the terms we, us, our and Cameco mean Cameco Corporation and its subsidiaries, including NUKEM Energy Gmbh (NUKEM), unless otherwise indicated.
- End -
Investor inquiries:
Rachelle Girard
(306) 956-6403
Media inquiries:
Gord Struthers
(306) 956-6593