Cameco reports fourth quarter and 2013 financial results strong performance in a weak market delivered record annual consolidated revenue strong uranium segment results – record annual revenue and average realized price
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 fourth quarter and 2013 financial results
- strong performance in a weak market
- delivered record annual consolidated revenue
- strong uranium segment results – record annual revenue and average realized price
- record quarterly and annual uranium production
- began jet boring in ore at Cigar Lake
- recorded a $70 million write-down on Talvivaara asset
- announced the sale of our interest in Bruce Power Limited Partnership
Saskatoon, Saskatchewan, Canada, February 7, 2014 . . . . . . . . . . . . . . . . . .
Cameco (TSX: CCO; NYSE: CCJ) today reported its consolidated financial and operating results for the fourth quarter and year ended December 31, 2013 in accordance with International Financial Reporting Standards (IFRS).
“2013 was a challenging year, but also a year in which Cameco was, again, able to demonstrate resilience and strength,” said president and CEO, Tim Gitzel. “We were able to achieve record production and a number of record financial results, despite the continued uncertainty in the uranium market.
That uncertainty has lasted for longer than had been expected, and this year, we’ve moved away from our production target of 36 million pounds by 2018. Although we still have an extensive portfolio of assets from which we can increase our production, the market incentive must be there. We’re confident this change will ensure we have the flexibility to remain competitive, create value for shareholders, and benefit when certainty and growth return to the market over the long term.”
| HIGHLIGHTS | THREE MONTHS ENDED | YEAR ENDED | ||||
|---|---|---|---|---|---|---|
| ($ MILLIONS EXCEPT PER SHARE | DECEMBER 31 | DECEMBER 31 | ||||
| AMOUNTS) | 2013 | 2012 | CHANGE | 2013 | 2012 | CHANGE |
| Revenue | 977 | 846 15% | 2,439 | 1,891 29% | ||
| Gross profit | 185 | 255 (27)% | 607 | 540 12% | ||
| Net earnings attributable to equity holders | 64 | 41 56% | 318 | 253 26% | ||
| $ per common share (basic and diluted) | 0.16 | 0.10 60% | 0.81 | 0.64 27% | ||
| Adjusted net earnings (non-IFRS, see page 10) | 150 | 233 (36)% | 445 | 434 3% | ||
| $ per common share (adjusted and diluted) | 0.38 | 0.59 (36)% | 1.12 | 1.10 2% | ||
| Cash provided by operations (after working capital changes) | 286 (46)% | 579 (8)% | ||||
| 154 | 530 | |||||
| Average Uranium $US/lb realized prices $Cdn/lb Fuel services $Cdn/kgU NUKEM $Cdn/lb Electricity $Cdn/MWh | 47.76 | 49.97 (4)% 49.37 1% | 48.35 | 47.72 1% 47.72 4% | ||
| 49.80 | 49.81 | |||||
| 17.24 | 17.16 - | 18.12 | 17.75 2% | |||
| 41.84 | - - | 42.26 | - - | |||
| 54 | 54 - | 54 | 55 (2)% |
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The 2013 annual financial statements have been audited; however, the 2012 and 2013 fourth quarter financial information presented is unaudited. You can find a copy of our 2013 audited financial statements on our website at cameco.com. Our 2013 annual management’s discussion and analysis (MD&A) will be posted on our website before markets open on Monday, February 10, 2014.
Starting in the first quarter of 2013, IFRS 11 – Joint Arrangements requires that we account for our interest in Bruce Power Limited Partnership (BPLP) using equity accounting. Our results for 2012 have been revised for comparative purposes.
FULL YEAR
Our net earnings attributed to equity holders (net earnings) were $318 million ($0.81 per share diluted) compared to $253 million ($0.64 per share diluted) in 2012, mainly due to:
- the impact of a one-time $168 million write-down of our investment in the Kintyre project in 2012
- higher earnings from our fuel services business as a result of an increase in sales volumes and realized prices
- lower exploration expenditures due to a decreased activity at our Kintyre project in Australia
- higher tax recoveries due to a decline in pre-tax earnings in Canada
partially offset by:
- lower earnings from our electricity business due to lower generation, a lower average realized price and higher costs
- a $70 million write-down of our Talvivaara asset due to their weakened financial position and pending corporate restructuring
- higher losses on foreign exchange derivatives due to the weakening of the Canadian dollar
On an adjusted basis, our earnings were $445 million ($1.12 per share diluted) (non-IFRS measure, see page 10) compared to $434 million ($1.10 per share diluted) in 2012, mainly due to:
- addition of gross profit from NUKEM
- lower exploration costs due to a decrease in activity at our Kintyre project in Australia
- lower income taxes
partially offset by:
- lower earnings from our electricity business due to lower generation, a lower average realized price and higher costs
See 2013 Financial results by segment on page 13 for more detailed discussion.
FOURTH QUARTER
In the fourth quarter of 2013, our net earnings were $64 million ($0.16 per share diluted), an increase of $23 million compared to $41 million ($0.10 per share diluted) in 2012, mainly due to:
- the impact of a one-time $168 million write-down of our investment in the Kintyre project in the fourth quarter of 2012
- lower exploration and administrative expenditures
- higher income tax recovery
offset by:
- lower uranium gross profits due to lower sales volumes and higher average unit cost of sales
- a $70 million write-down of our Talvivaara asset, due to their weakened financial position and pending corporate restructuring
- higher losses on foreign exchange derivatives due to the weakening of the Canadian dollar
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On an adjusted basis, our earnings this quarter were $150 million ($0.38 per share diluted) compared to $233 million ($0.59 per share diluted) (non-IFRS measure, see page 10) in the fourth quarter of 2012, mainly due to:
- lower uranium gross profits due to lower sales volumes and higher average unit cost of sales
offset by:
- lower exploration and administrative expenditures
- higher income tax recovery
See 2013 Financial results by segment on page 13 for more detailed discussion.
IMPAIRMENT CHARGE ON NON-PRODUCING ASSETS
During the fourth quarter of 2013, we recognized a $70 million impairment charge relating to our agreement with Talvivaara Mining Company Plc. to purchase uranium produced at the Sotkamo nickel-zinc mine in Finland. The impairment charge represents the full amount of our investment, which was used to cover construction costs, with the amount to be repaid through deliveries of uranium concentrate. The amount of the charge was determined as the excess of the carrying value over the fair value, less costs to sell. Due to Talvivaara’s weak financial position and application to the Finnish government to undergo a corporate restructuring, as an unsecured creditor, we determined the fair value less costs to sell to be nil, and as such, recognized an impairment charge for the full amount of the asset.
The nuclear energy industry today
The long-term outlook for the uranium industry continues to be very positive, despite the uncertainty that exists today. Against the backdrop of the world’s growing need for safe, clean, reliable and large-scale sources of energy, nuclear energy continues to play a significant role in the global energy mix. The challenge for the industry is the pathway and timing of the transition from today’s stagnant, over-supplied short-term market to the promise of nuclear growth and positive uranium market conditions in the long term.
Market conditions deteriorated in 2013 and we believe the uncertainty could continue, depending on how events unfold. In particular, the slower than expected pace of Japanese reactor restarts, unexpected reactor shutdowns in the United States and temporary shutdowns in South Korea led to demand erosion. Compounding the issue, the supply side performed well: primary supply remained stable while secondary supply increased modestly, primarily due to enricher underfeeding. The impact of these conditions was the extension of the post-Fukushima inventory overhang and further downward price pressure.
This market dynamic also led to a reduction in market contracting activity. Utilities are well covered under long-term contracts for the time being and are not under pressure to buy. Similarly, existing suppliers appear reluctant to enter into meaningful contract volumes at current prices. The result was very low levels of long-term contracting in 2013— around 10% of current annual reactor consumption estimates, highlighting a cordial stalemate between buyers and sellers. How this stalemate is resolved between buyers and sellers will be a key factor influencing the pace of market recovery.
Looking beyond the current market challenges, there were several positive indications for the long term in 2013. In Japan, more clarity was gained around the process for reactor restarts: the Nuclear Regulatory Authority (NRA) implemented measures that improved regulatory stability; restart applications were submitted by seven utilities covering 16 reactors; and, there was observable confidence from Japanese utilities who are spending billions of dollars on plant upgrades in anticipation of a positive restart environment.
In other regions, China’s remarkable nuclear growth program remains on track. Three more reactors were brought online, and construction began on four more in 2013. The United Kingdom (UK) also garnered positive attention as a result of a government-backed revenue arrangement with Électricité de France, designed to support new build there.
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Overall, the anticipated increase in nuclear plants from 433 (representing 394 gigawatts) today to 526 (representing 514 gigawatts) by 2023 illustrates a promising growth picture.
And it is clear that this growth will require new sources of uranium supply at a time when secondary supplies are diminishing and current market conditions have resulted in deferrals and cancellations of several uranium projects. Current prices are insufficient to incent new production. The end of the Russian Highly Enriched Uranium (HEU) commercial agreement in 2013, removing 24 million pounds of annual supply from the market, highlights the need for increasing reliance on primary uranium supply in the future. The timing of this required supply may well be muted in the near term due to the extension of the over-supply situation, but it remains clear new supply will be required this decade. The development and execution of new uranium supply projects, as well as continued performance of existing supply, will also play a significant role in determining the timing and pace of market recovery.
Our strategy
Our strategy remains focused on taking advantage of the long-term growth we see coming in our industry, while maintaining the ability to respond to market conditions as they evolve. As a result of the longer-than-anticipated market uncertainty, we are adjusting our plans in line with this focus.
Market challenges have persisted since early 2011 and we expect they will continue for the near to medium term, depending on:
- the pace of Japanese reactor restarts
- how long it takes for excess supply to clear the market
- when long-term contracting resumes in meaningful quantities
- the development and execution of new uranium supply projects
- continued performance of existing supply
In this environment, a fixed production target is no longer appropriate; although we still have an extensive portfolio of assets from which we can increase production capacity, we have decided the prudent action is to eliminate our previous 2018 supply target of 36 million pounds. This will allow us increased flexibility in order to deliver the best value through this period of uncertainty, while at the same time retaining the ability to benefit when more certainty returns to the market environment, as we expect it will. Today, our strategy is to profitably produce at a pace aligned with market signals to increase long-term shareholder value.
We plan to:
- carry out all of our business with a focus on safety, people and the environment
- ensure continued reliable, low-cost production from our flagship operation, McArthur River/Key Lake and seek to expand that production
- ensure continued reliable, low-cost production at Inkai
- successfully bring on and ramp up production at Cigar Lake
- manage the rest of our production facilities and potential sources of supply in a manner that retains the flexibility to respond to market signals and take advantage of value adding opportunities within our own portfolio and the uranium market
- manage and allocate capital in a way that balances growing the long-term value of the business and returns to shareholders, while maintaining a strong balance sheet and our investment grade rating
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Outlook for 2014
Our strategy is to profitably produce at a pace aligned with market signals, while maintaining the ability to respond to conditions as they evolve.
Our outlook for 2014 reflects the expenditures necessary to help us achieve our strategy. 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 13 for details.
2014 FINANCIAL OUTLOOK
Subject to closing, we sold our interest in BPLP effective December 31, 2013, and we will no longer provide an outlook for the electricity segment.
| CONSOLIDATED | URANIUM | FUEL SERVICES | NUKEM | |
|---|---|---|---|---|
| Production | 23.8 to 24.3 - million lbs | 13 to 14 | - | |
| million kgU | ||||
| Sales volume | 31 to 33 - million lbs | Decrease | 9 to 11 million lbs UO 3 8 | |
| 5% to 10% | ||||
| Increase 0% to 5% | Increase | Decrease Increase 5% to 10% 0% to 5% | ||
| Revenue compared to 2013 | ||||
| 0% to 5%1 | ||||
| Average unit cost of sales | - | Increase Increase 0% to 5% 0% to 5% | ||
| Increase | ||||
| (including depreciation and | 0% to 5%2 | |||
| amortization (D&A)) | ||||
| Direct administration costs compared | Increase 0% to 5% | Increase - 0% to 5% | ||
| - | ||||
| to 20133 | ||||
| Exploration costs compared to 2013 | - | Decrease | - - | |
| 35% to 40% | ||||
| Recovery of 30% to 35% | Expense of - 30% to 35% | |||
| Tax rate | - | |||
| Capital expenditures | $495 million | - | - | - |
1 Based on a uranium spot price of $35.50(US) per pound (the Ux spot price as of February 3, 2014), a long-term price indicator of $50.00 (US) per pound (the Ux long-term indicator on January 27, 2014) and an exchange rate of $1.00 (US) for $1.03 (Cdn).
2 This increase is based on the unit cost of sale for produced material and committed long-term purchases. If we make discretionary purchases in 2014 then we expect the overall unit cost of sales to increase further.
3 Direct administration costs do not include stock-based compensation expenses.
CONSOLIDATED OUTLOOK
We expect consolidated revenue to be up to 5% higher in 2014 due to an increase in realized prices in our uranium business.
We expect administration costs (not including stock-based compensation) to be relatively stable (0% to 5% higher) compared to 2013, as restructuring efforts offset inflation.
We expect exploration expenses to be about 35% to 40% lower than they were in 2013 due to:
- decreased activities in Australia
- a general reorganization of our global exploration portfolio that has allowed us to focus on our core projects in Saskatchewan
We have contractual arrangements to sell uranium produced at our Canadian mining operations to a trading and marketing company located in a foreign jurisdiction. These arrangements reflect the uranium markets at the time they were signed, with the risk and benefit of subsequent movements in uranium prices accruing to the foreign trading and marketing company.
On an adjusted net earnings basis, we expect a tax recovery of 30% to 35% in 2014 from our uranium, fuel services and NUKEM segments, as taxable income in Canada is expected to decline. Subject to our success in the litigation
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with CRA, we expect our tax recovery to continue in accordance with the 2014 outlook until the contractual arrangements noted above expire in 2016. As these arrangements expire and are replaced by new contracts that reflect the uranium market at the time of signing, our tax expense is expected to rise over time. See page 10 in this document and note 22 to the financial statements for more information.
URANIUM OUTLOOK
We expect to produce 23.8 million to 24.3 million pounds in 2014 and have commitments under long-term contracts to purchase approximately 2 million pounds.
Based on the contracts we have in place, we expect to deliver between 31 million and 33 million pounds of U3O8 in 2014. We expect the unit cost of sales to be up to 5% higher than in 2013, primarily due to higher costs for produced material. In 2014, we will complete a number of capital projects at our various production facilities, including Cigar Lake. Upon completion, we will begin to depreciate the assets, which will increase the non-cash portion of our production costs. In addition, until Cigar Lake ramps up to full production, the cash cost of material produced from the mine will initially be higher. If we make additional discretionary purchases in 2014, then we expect the overall unit cost of sales to increase further.
Based on current spot prices, revenue should be up to 5% higher than it was in 2013 as a result of an expected increase in the realized price.
In our uranium and fuel services segments, our customers choose when in the year to receive deliveries, so our quarterly delivery patterns and, therefore, our sales volumes and revenue, can vary significantly. We expect that uranium deliveries in the first quarter of 2014 will be slightly higher than the first quarter of 2013, with about 20% of the year’s deliveries scheduled for the first three months. We expect uranium deliveries for the balance of 2014 to be more heavily weighted (~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.
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 is designed to indicate how the portfolio of long-term contracts we had in place on December 31, 2013 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 December 31, 2013, and none of the assumptions we list below change.
We intend to update this table each quarter in our MD&A to reflect deliveries made and changes to our contract portfolio each quarter. As a result, we expect the table to change from quarter to quarter.
Expected realized uranium price sensitivity under various spot price assumptions
(rounded to the nearest $1.00)
| SPOT PRICES | |||||||
|---|---|---|---|---|---|---|---|
| ($US/lb UO) 3 8 | $20 | $40 | $60 | $80 | $100 | $120 | $140 |
| 2014 | 45 | 48 | 55 | 62 | 69 | 76 | 81 |
| 2015 | 41 | 46 | 55 | 65 | 75 | 84 | 93 |
| 2016 | 42 | 47 | 57 | 68 | 78 | 88 | 96 |
| 2017 | 42 | 47 | 57 | 67 | 77 | 86 | 93 |
| 2018 | 43 | 49 | 58 | 68 | 78 | 86 | 93 |
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The table illustrates the mix of long-term contracts in our December 31, 2013 portfolio, and is consistent with our marketing strategy. It has been updated to reflect deliveries made and contracts entered into up to December 31, 2013.
Our portfolio includes a mix of fixed-price and market-related contracts, which we target at a 40:60 ratio. Those that are fixed at lower prices or have low ceiling prices will yield prices that are lower than current market prices.
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 Inflation
- sales volumes on average of 30 million pounds per
- is 1.5% in Canada and 2% per year in the US
year, with commitment levels through 2016 higher
Prices
than in 2017 and 2018
- the average long-term price indicator is the same
Deliveries
as the average spot price for the entire year (a
- deliveries include best estimates of requirements simplified approach for this purpose only). Since contracts and contracts with volume flex provisions 1996, the long-term price indicator has averaged
- we defer a portion of deliveries under existing 17% higher than the spot price. This differential contracts for 2014 has varied significantly. Assuming the long-term price is at a premium to spot, the prices in the table will be higher.
ROYALTIES
On January 3, 2014, the government of Saskatchewan released regulations to implement the changes to the Saskatchewan uranium royalty system originally announced in the 2013 provincial budget.
The government has 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% royalty will be charged on profit up to and including $22/kg U3O8 ($9.98/lb), and a 15% royalty on profit in excess of $22/kg U3O8. Profit will be determined as revenue less certain operating, exploration, reclamation and capital costs (applied to Saskatchewan uranium production). Under the new system, both exploration and capital costs will be deductible at the discretion of the producer.
During the period from 2013 to 2015, transitional rules will apply whereby only 50% of capital costs will be deductible. The remaining 50% will be accumulated and deductible commencing in 2016. In addition, the capital allowance related to Cigar Lake under the previous system, will be grandfathered and deductible in 2016.
Also, as previously reported, the net basic royalty (basic royalty of 5% less the Saskatchewan resource credit) increased from 4.0% to 4.25% effective April 1, 2013. Other than the increase of the rate, there were no changes to the determination of the basic royalty, which continues to be levied by the province on the gross revenue from the sales of Saskatchewan uranium production.
LONG-TERM URANIUM PRODUCTION OUTLOOK
Although we have an extensive portfolio of assets from which we can increase our production capacity, we have eliminated our 2018 supply target of 36 million pounds in order to allow us to respond to market signals, and as a result, it is no longer appropriate to provide a long-term production forecast.
FUEL SERVICES OUTLOOK
In 2014, we plan to produce 13 million to 14 million kgU, and we expect sales volumes to be 5% to 10% lower than in 2013. Overall revenue is expected to decrease by 5% to 10% as a result of the lower sales volumes. We expect the
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unit cost of product sold (including D&A) to increase by 0% to 5%; therefore, overall gross profit will decrease as a result.
NUKEM OUTLOOK
Much of the purchase price for NUKEM 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.
For 2014, NUKEM expects to deliver between 9 million and 11 million pounds of uranium, resulting in an increase in total revenues of up to 5% compared to 2013. NUKEM expects to incur administration costs similar to 2013. The effective income tax rate is expected to remain in the range of 30% to 35%.
CAPITAL SPENDING
We classify capital spending as sustaining, capacity replacement or growth. As a mining company, sustaining capital is the money we spend to keep our facilities running in their present state, which would follow a gradually decreasing production curve, while capacity replacement capital is spent to maintain current production levels at those operations. Growth capital is money we invest to generate incremental production, and for business development.
| CAMECO’S SHARE ($ MILLIONS) | 2013 PLAN | 2013 ACTUAL | 2014 PLAN |
| Sustaining capital | |||
| McArthur River/Key Lake | 55 | 64 | 30 |
| Cigar Lake | - | - | 15 |
| Rabbit Lake | 70 | 50 | 40 |
| US ISR | 5 | 5 | 5 |
| Inkai | 7 | 1 | 5 |
| Fuel services | 10 | 8 | 10 |
| Other | 23 | 9 | 10 |
| Total sustaining capital | 170 | 137 | 115 |
| Capacity replacement capital | |||
| McArthur River/Key Lake | 75 | 73 | 60 |
| Cigar Lake | - | - | 25 |
| Rabbit Lake | 5 | 3 | 15 |
| US ISR | 30 | 22 | 20 |
| Inkai | 20 | 16 | 15 |
| Total capacity replacement capital | 130 | 114 | 135 |
| Growth capital | |||
| McArthur River/Key Lake | 55 | 29 | 75 |
| US ISR | 30 | 33 | 10 |
| Millennium | 5 | 5 | 5 |
| Inkai | 21 | 9 | 5 |
| Cigar Lake | 260 | 284 | 145 |
| Fuel Services | 4 | 2 | 5 |
| Total growth capital | 375 | 362 | 245 |
| Talvivaara | 10 | 10 | - |
| Total uranium & fuel services 6851 623 | 495 | ||
| Electricity (our 31.6% share of BPLP) | 80 | 75 | - |
1 We updated our 2013 capital cost estimate in the Q2 MD&A to $685 million.
Capital expenditures were 9% below our 2013 plan, mainly due to variances at Rabbit Lake, Inkai, and McArthur River/Key Lake caused by a change in the timing of expenditures.
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| (CAMECO’S SHARE IN $ MILLIONS) | 2015 PLAN | 2016 PLAN |
| Total uranium & fuel services | 400-450 | 500-550 |
| Sustaining capital | 160-175 | 220-240 |
| Capacity replacement capital | 150-170 | 165-175 |
| Growth capital | 90-105 | 115-135 |
We expect total capital expenditures for uranium and fuel services to decrease by about 21% in 2014.
Major sustaining, capacity replacement and growth expenditures in 2014 include:
- McArthur River/Key Lake – At McArthur River, the largest project is the upgrade of the electrical infrastructure at about $56 million. Mine development is also planned at about $105 million. Other projects include expansion of freeze capacity and other site facility and equipment purchases. At Key Lake, projects will be undertaken to finish work on the calciner and upgrade site electrical services
- US in situ recovery (ISR) – Continued work on the development of the North Butte mine represents a large portion of our wellfield construction expenditures in the US. Well installation at other mine units is also significant.
- Rabbit Lake – At Eagle Point, the largest component is mine development at about $24 million, along with mine equipment upgrades and purchases. Work on various mill facility and equipment replacements will also continue.
- Cigar Lake – Underground mine development makes up the largest portion of capital at the Cigar Lake site, at about $30 million. Completion of various mine facilities will continue into 2014, as well as the purchase of mine equipment in order to ramp up to full production. Our share of the costs to modify the McClean Lake mill are expected to be about $100 million in 2014.
We previously estimated capital costs on our brownfield expansions and development projects to be between $135 and $190 million per year for the next three years. We now estimate capital costs for our brownfield expansions and development projects to be about $245 million in 2014 due to the delayed startup of Cigar Lake production and additional costs at the McClean Lake mill. Growth capital is then expected to be between $90 and $135 million per year for 2015 and 2016.
The removal of our fixed production target allows us to better align our capital spending with market signals. As the market begins to signal new production is needed, we plan to increase our capital expenditures to allow us to be among the first to respond to the growth we see coming.
This information regarding currently expected capital expenditures for future periods is forward-looking information, and is based upon the assumptions and subject to the material risks discussed beginning on page 22. Our actual capital expenditures for future periods may be significantly different.
ACQUISITIONS AND DIVESTITURES
On January 9, 2013 we completed the acquisition of NUKEM by paying a total of $140 million (US) and assuming its net debt of $111 million (US). In the third quarter of 2013, as part of our strategy to focus on projects that provide the most certainty in the near term, we divested our interests in Argentina and Peru and recorded a loss of $15 million.
On January 30, 2014, we signed an agreement with BPC Generation Infrastructure Trust to sell our 31.6% limited partnership interest in BPLP and related entities for $450 million. The effective date for the sale is December 31, 2013. We expect to realize an after tax gain of approximately $129 million on this divestiture.
Under the agreements governing BPLP, the limited partners have rights of first offer upon a sale by us. Closing of the transaction is subject to completion or waiver of the right of first offer process by the other limited partners and receipt of certain regulatory approvals.
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SENSITIVITY ANALYSIS
At December 31, 2013, every one-cent change in the value of the Canadian dollar versus the US dollar would change our 2014 net earnings by about $5 million (Cdn), 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).
For 2014, a change of $5 (US) per pound in each of the Ux spot price ($35.50 (US) per pound on February 3, 2014) and the Ux long-term price indicator ($50.00 (US) per pound on January 27, 2014) would change revenue by $67 million and net earnings by $42 million.
NON-IFRS MEASURES – ADJUSTED NET EARNINGS
Adjusted net earnings is a measure that does not have a standardized meaning or a consistent basis of calculation under IFRS (non-IFRS measure). We use this measure as a more meaningful way to compare our financial performance from period to period. We believe that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate our performance. Adjusted net earnings is our net earnings attributable to equity holders, adjusted to better reflect the underlying financial performance for the reporting period. The adjusted earnings measure reflects the matching of the net benefits of our hedging program with the inflows of foreign currencies in the applicable reporting period, and adjusted for impairment charges on nonproducing properties, NUKEM inventory write-down, loss on exploration properties, and income taxes on adjustments.
Adjusted net earnings is non-standard supplemental information and should not be considered in isolation or as a substitute for financial information prepared according to accounting standards. Other companies may calculate this measure differently, so you may not be able to make a direct comparison to similar measures presented by other companies.
To facilitate a better understanding of these measures, the table below reconciles adjusted net earnings with our net earnings for the years ended 2013, 2012 and 2011, as reported in our financial statements.
| ($ MILLIONS) | 2013 | 2012 | 2011 |
| Net earnings attributable to equity holders | 318 | 253 | 450 |
| Adjustments | |||
| Adjustments on derivatives1 (pre-tax) | 56 | 17 | 80 |
| Impairment charge on non-producing property | 70 | 168 | - |
| NUKEM inventory write-down | 14 | - | - |
| Loss on exploration properties | 15 | - | - |
| Income taxes on adjustments | (28) | (4) | (21) |
| Adjusted net earnings | 445 | 434 | 509 |
1 We do not apply hedge accounting for our portfolio of foreign currency forward sales contracts. However, we have adjusted our gains or losses on derivatives to reflect what our earnings would have been had hedge accounting been in place.
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 2008 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.
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
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As the majority of our customers are located outside Canada, we established an offshore marketing subsidiary. This subsidiary entered into 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 them 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 entered into at that time. We have recorded a cumulative tax provision of $73 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 2013.
We are confident that we will be successful in our case; however, for the years 2003 through 2008, CRA issued notices of reassessment for approximately $2.0 billion of additional income for Canadian tax purposes, which would result in a related tax expense of about $590 million. The Canadian Income Tax Act includes provisions that require certain companies to pay 50% of the cash tax plus related interest and penalties at the time of reassessment. To date, under these provisions, after applying elective deductions and tax loss carryovers, we have been required to pay a net amount of $103 million to CRA ($59 million as of December 31, 2013; $44 million in January 2014), which includes the amounts shown in the table below and described subsequently.
| INTEREST AND | TRANSFER PRICING | |||
|---|---|---|---|---|
| YEAR ($ MILLIONS) | CASH TAXES | INSTALMENT PENALTIES | PENALTIES | TOTAL |
| Prior to 2013 | - 13 - | 13 | ||
| 2013 | 1 9 36 | 46 | ||
| 2014 | 16 28 - | 44 | ||
| Total | 17 50 36 | 103 |
- approximately $13 million for interest and instalment penalties paid prior to 2013. These amounts were not reported separately as they were not material in any given year.
- approximately $27 million in January 2013, representing 50% of the amount owed for the amounts reassessed in December 2012 — $20 million of this payment was refunded in the second quarter of 2013 when it was determined by CRA that they had reassessed amounts outside of the allowable review period
- approximately $36 million in December 2013 that related to a $72 million transfer pricing penalty we were assessed for the 2007 taxation year. This was the first transfer pricing penalty assessed since CRA began to issue reassessments with respect to the transfer pricing dispute.
- approximately $3 million paid in 2013. This amount would have been refundable in the year, but instead was applied as a credit against the amounts reassessed in December 2013 (for which a further payment was made in January 2014).
- approximately $44 million in January 2014, representing 50% of the amount owed as reassessed in December 2013 and related to the 2008 taxation year
Using the methodology we believe CRA will continue to apply, and including the $2.0 billion already reassessed, we expect to receive notices of reassessment for a total of approximately $5.7 billion in income as taxable in Canada for the years 2003 through 2013, which would result in a related tax expense of approximately $1.6 billion. As well, CRA may continue to apply transfer price penalties to taxation years subsequent to 2007. As a result, we estimate that cash taxes and transfer pricing penalties would be between $1.25 billion and $1.3 billion. 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 and transfer pricing penalties (between $625 million and $650 million) plus related interest and instalment penalties assessed, which would be material to Cameco.
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Under the Canadian federal and provincial tax legislation, the amount required to be remitted each year will depend on the amount of income reassessed in that year and the availability of elective deductions and tax loss carryovers; however, we expect it will generally follow the schedule in the table below.
| TOTAL | ||||
|---|---|---|---|---|
| DECEMBER 31, 2013 ($ MILLIONS) | 2003 - 2013 | 2014 - 2016 | 2017 - 2023 | |
| 50% of cash taxes and transfer pricing penalties | 37 250 – 275 325 - 350 | |||
| 625 - 650 | ||||
| payable in the period1 |
1 These amounts do not include interest and instalment penalties, which totaled approximately $22 million to December 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 $103 million already paid to date.
The case on the 2003 reassessment is expected to go to trial in 2015. If this timing is adhered to, we expect to have a Tax Court decision in 2015 or 2016.
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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, transfer pricing penalties and interest and possible instalment 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 beginning on page 22 and also on the more specific assumptions and risks listed below. Actual outcomes may vary significantly.
Material risks that could cause actual results to Assumptions differ materially
- CRA will reassess us for the years 2009 through
- CRA reassesses us for years 2009 through 2013
2013 using a similar methodology as for the years using a different methodology than for years 2003 2003 through 2008, with the time lag for the through 2008, or we are unable to utilize elective reassessments for each year being similar to what deductions and loss carryovers to the same extent has occurred to date as anticipated, resulting in the required cash
- we will be able to apply elective deductions and tax payments to CRA pending the outcome of the loss carryovers to the extent anticipated dispute being higher than expected
- CRA will seek to impose transfer pricing penalties
- the time lag for the reassessments for each year is
(10% of the income adjustment) in addition to different than for those to date interest charges and instalment penalties
- we are unsuccessful and the outcome of our dispute
- we will be substantially successful in our dispute with with CRA results in significantly higher cash taxes, CRA and the cumulative tax provision of $73 million interest charges and penalties than the amount of to date will be adequate to satisfy any tax liability our cumulative tax provision, which could have a resulting from the outcome of the dispute to date 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
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