MANAGEMENT’S DISCUSSION AND ANALYSIS
This management’s discussion and analysis (MD&A) should be read in conjunction with the consolidated financial statements included in this Annual Report. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). The effect of significant differences between Canadian and U.S. GAAP has been disclosed inNote 26to the consolidated financial statements. All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted. This MD&A is current as of Feb. 17, 2005. Additional information respecting TransAlta Corporation (TransAlta or the corporation), including its annual information form, is available on SEDAR at www.sedar.com.
F O R W A R D - L O O K I N G S TAT E M E N T S
This MD&A contains forward-looking statements, including statements regarding the business and anticipated financial performance of TransAlta. In some cases, forward-looking statements can be identified by terms such as ‘may’, ‘will’, ‘believe’, ‘expect’, ‘potential’, ‘enable’, ‘continue’ or other comparable terminology. These statements are not guarantees of TransAlta’s future performance and are subject to risks, uncertainties and other important factors that could cause the corporation’s actual performance to be materially different from those projected. Some of the risks, uncertainties and factors include, but are not limited to: legislative and regulatory developments that could affect revenues, costs and the speed and degree of competition entering the market; global capital markets activity; timing and extent of changes in commodity prices, prevailing interest rates, currency exchange rates, inflation levels and general economic conditions in geographic areas where TransAlta operates; results of financing efforts; changes in counterparty risk; and the impact of accounting policies issued by Canadian and U.S. standard setters. Given these uncertainties, the reader should not place undue reliance on these forward-looking statements. See additional discussion under Risk Factors and Risk Management in this MD&A.
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R E S U LT S O F O P E R AT I O N S The results of operations are presented on a consolidated basis and by business segment. TransAlta has two business segments: Generation and Energy Marketing. TransAlta’s Transmission operations were sold on April 29, 2002. Prior period amounts have been reclassified to reflect this change. TransAlta’s segments are supported by a corporate group that provides finance, treasury, legal, human resources and other administrative support. These corporate group overheads are allocated to the business segments if they are not directly attributable to discontinued operations. Some of the corporation’s accounting policies require management to make estimates or assumptions that in some cases may relate to matters that are inherently uncertain. Critical accounting policies and estimates for TransAlta include: revenue recognition; valuation and useful life of property, plant and equipment (PP&E); asset retirement obligations; valuation of goodwill; income taxes; and employee future benefits. See additional discussion under Critical Accounting Policies and Estimates in this MD&A. TransAlta measures capacity as net maximum capacity (see glossary for definition of this and other key terms), which is consistent with industry standards. Capacity figures represent capacity owned and in operation unless otherwise stated. In this MD&A, the impact of foreign exchange fluctuations on foreign currency transactions and balances is discussed with the relevant income statement and balance sheet items. While individual balance sheet line items will be impacted by foreign exchange fluctuations, the net impact of the translation of individual items is reflected in the cumulative translation account on the consolidated balance sheet. C E RT I F I C AT I O N The corporation’s disclosure controls and procedures have enabled the certification of TransAlta’s annual report to shareholders in compliance with the requirements of Section 302 of the Sarbanes-Oxley Act and its annual filings as defined in and in compliance with the requirements of Multilateral Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings”. S T R AT E G Y A N D K E Y P E R F O R M A N C E I N D I C AT O R S Strategy The corporation’s strategy is to deliver sustainable and increasing earnings and cash flow through operations and growth of a diversified portfolio of power generating assets. To implement this strategy, TransAlta focuses on maintaining a strong balance sheet, minimizing costs, utilizing existing assets efficiently and carefully managing the risk profile while methodically growing capacity. In 2004, TransAlta increased net generating capacity by 68 megawatts (MW) as the Summerview Wind Farm was commissioned in the third quarter. TransAlta has 225 MW of capacity under construction at the Genesee 3 project and also has 540 MW approved for development. Genesee 3 is expected to be commissioned in the first quarter of 2005. At Dec. 31, 2004, TransAlta had 9,102 MW of owned capacity in operation, under construction or approved for development. Availability is a key driver of TransAlta’s financial results as approximately 81 per cent of the Generation segment’s revenues are derived from contracts with either production or availability components. In 2004, TransAlta spent $173.8 million on planned maintenance and maintained availability at 89.1 per cent as compared to 90.6 per cent in 2003. TransAlta’s goal is to have an overall availability of at least 90 per cent. As a result of the increased capacity, production also increased by 3 per cent to 54,560 gigawatt hours (GWh) in 2004. Long-term contracts minimize TransAlta’s exposure to market price fluctuations and provide a stable stream of revenues to support fixed operating costs, pay interest and recover capital expenditures. The corporation also reserves a portion of its capacity to be available to be sold at market rates. In 2004, 84 per cent of the corporation’s production was sold under contracts with durations of at least 12 months and 71 per cent was sold under contracts with original terms of 10 years or more. Energy Marketing is vital to delivering sustainable revenues. Energy Marketing acts to maximize margins from the production and sale of electricity, minimize the cost of natural gas used to generate electricity and steam and reduce the risk to the corporation from unplanned outages by acquiring replacement power at the lowest possible price. To minimize risk, TransAlta’s long-term goal is to diversify market and fuel source exposure and balance the age of generation plants.
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TransAlta is positioning itself to meet the requirements of a Canadian climate change program expected in 2008. In addition to increasing production from renewable sources, the corporation will manage climate change regulations through the continued investment in emission offset credits, development of clean coal technology, and internal efficiency improvements. The corporation has reduced its worldwide greenhouse gas intensity by 13 per cent from 1990 levels while increasing generation by over 80 per cent. TransAlta also has a longer-term strategy to seek emission reduction opportunities as its existing plants are retired and as new combustion and environmental technology is developed to further reduce emissions. TransAlta has strategic alliances with EPCOR Utilities Inc. (EPCOR), ENMAX Corporation (ENMAX) and MidAmerican Energy Holdings Company (MidAmerican). The EPCOR alliance provided the opportunity for TransAlta to acquire a 50 per cent ownership in the 450 MW Genesee 3 project. ENMAX and TransAlta each own 50 per cent of the partnership in the McBride Lake wind project. MidAmerican owns the other 50 per cent interest in CE Generation LLC (CE Gen). TransAlta is focused on maintaining a strong balance sheet and investment grade credit ratings. At Dec. 31, 2004, TransAlta’s total debt (including non-recourse debt) to invested capital ratio was 47.4 per cent (42.0 per cent excluding non-recourse debt) compared to the Dec. 31, 2003 ratio of 47.7 per cent and the Dec. 31, 2002 ratio of 50.4 per cent. Debt to invested capital is defined on page 102 of this annual report. Key Performance Indicators For the Generation segment, key performance indicators (KPIs) include availability, production, fuel and operating costs, and pricing applicable to non-contracted production. For the Energy Marketing segment, KPIs include trading volumes, margins and value at risk (VAR), which is a measure used to manage earnings exposure from proprietary (non asset-backed) trading activities. Each of these KPIs is discussed in greater detail in Segmented Business Results in this MD&A. KPIs for the corporate segment include the debt to invested capital ratio, interest- and debt-coverage ratios and credit ratings. These KPIs are discussed under Liquidity and Capital Resources. M A R K E T T R E N D S Fluctuations in power supply and demand, together with changes in fuel prices, contribute to power price variations from year to year. Such changes in the price of electricity have an influence on TransAlta’s financial performance. In response to previously observed high power prices and increasingly deregulated market conditions, for instance, an overbuild of electricity generation has occurred across most of North America. This led to relatively weak power prices in 2002 before year-over-year demand growth and higher natural gas prices offered some recovery across markets in 2003. Subsequent moderation of natural gas prices, combined with measurable supply additions in each of Alberta and Ontario, contributed to a slight drop in power prices across those markets in 2004. To the contrary, the Pacific Northwest experienced further increases in gas prices in 2004, and with low hydro generation levels, electricity prices increased year over year. For 2005, electricity prices are expected to remain relatively steady across the three regional markets, particularly in Ontario. Power supply additions in Alberta are forecast to dominate expected gas price strength and suppress power prices slightly below 2004 levels, while Pacific Northwest demand growth and higher gas prices are forecast to increase power prices slightly above 2004 levels. Electricity prices generally increase as a result of higher natural gas prices. However, as experienced from 2002 through 2004 in Ontario and Alberta, stronger natural gas prices can also reduce spark spreads (the difference between the price of natural gas consumed to produce power and the selling price of electricity). The increases in electricity prices may not be completely correlated to the increase in natural gas prices due to the type and composition of generation that exists in the respective market. Lower spark spreads are forecast to continue in Alberta and Ontario, while spark spreads are forecast to remain relatively steady in the Pacific Northwest in 2005. In 2003 and 2004, the Canadian dollar appreciated significantly against the U.S. dollar. As the Canadian dollar appreciates, U.S.-denominated earnings decrease upon translation to Canadian dollars. During 2004, the Bank of Canada Target Overnight interest rate decreased from 2.75 per cent to 2.5 per cent at Dec. 31. In the U.S., the Federal Reserve Funding rate increased from 1.0 per cent to 2.25 per cent. Higher short term interest rates increase TransAlta’s interest expense to the extent the corporation has short-term debt that needs to be re-financed, or interest rate swaps under which TransAlta pays a floating rate of interest. Over the same time period, longer-term interest rates as represented by Government of Canada 10-year bond yields decreased from 4.66 per cent to 4.30 per cent in Canada, and in the U.S. as represented by the U.S.10-year treasury yield from 4.25 per cent to 4.22 per cent. Higher long-term interest rates increase TransAlta’s interest expense on any future debt financings.
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H I G H L I G H T S A N D S U M M A R Y O F R E S U LT S During 2004, the corporation:
The following table depicts key financial results and statistical operating data:
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Year ended Dec. 31 | 2004 | 20035 | 20025 | ||||||
Availability (%) | 89.1 | 90.6 | 88.4 | ||||||
Production (GWh)1 | 54,560 | 53,134 | 47,172 | ||||||
Electricity trading volumes (GWh)1 | 84,404 | 89,833 | 92,874 | ||||||
Gas trading volumes (million GJ)1 | 430.4 | 270.2 | 162.0 | ||||||
Revenue | $ | 2,838.3 | $ | 2,520.9 | $ | 1,814.9 | |||
Gross margin | $ | 1,409.3 | $ | 1,356.1 | $ | 1,059.3 | |||
Operating income2 and 6 | $ | 478.1 | $ | 561.6 | $ | 212.6 | |||
Earnings from continuing operations3 | $ | 160.6 | $ | 234.2 | $ | 66.8 | |||
Earnings from discontinued operations, net of tax4 | – | – | 12.8 | ||||||
Gain on disposal of discontinued operations, net of tax4 | 9.6 | – | 120.0 | ||||||
Net earnings applicable to common shareholders | $ | 170.2 | $ | 234.2 | $ | 199.6 | |||
Basic earnings per common share: | |||||||||
Earnings from continuing operations | $ | 0.83 | $ | 1.26 | $ | 0.39 | |||
Earnings from discontinued operations | – | – | 0.07 | ||||||
Net earnings from operations | $ | 0.83 | $ | 1.26 | $ | 0.46 | |||
Gain on disposal of discontinued operations, net of tax | 0.05 | – | 0.71 | ||||||
Net earnings | $ | 0.88 | $ | 1.26 | $ | 1.17 | |||
Diluted earnings per common share: | |||||||||
Earnings from continuing operations | $ | 0.83 | $ | 1.26 | $ | 0.39 | |||
Earnings from discontinued operations | – | – | 0.07 | ||||||
Net earnings from operations | $ | 0.83 | $ | 1.26 | $ | 0.46 | |||
Gain on disposal of discontinued operations, net of tax | 0.05 | – | 0.71 | ||||||
Net earnings | $ | 0.88 | $ | 1.26 | $ | 1.17 | |||
Cash flow from operating activities | $ | 613.4 | $ | 526.9 | $ | 398.6 | |||
1 | 2002 production and electricity and gas trading volumes have been restated to conform with current reporting practices and standards. |
2 | For reconciliation of operating income, see page 26 of this MD&A. |
3 | Continuing operations include the Generation and Energy Marketing segments plus corporate costs not directly attributable to discontinued operations. |
4 | Discontinued operations consist of the Transmission operation, which was sold on April 29, 2002. |
5 | TransAlta early adopted the amended standard on the presentation of liabilities and equity on Jan. 1, 2004. SeeNote 1to the consolidated financial statements for further discussion. Prior periods have been restated. |
6 | Operating income is not defined under GAAP. Refer to the Non-GAAP Measures section of this MD&A for a further discussion of operating income, including a reconciliation to net earnings. |
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In 2004, availability decreased to 89.1 per cent from 90.6 per cent in 2003 primarily due to higher planned maintenance activity. The increase in 2003 compared to 2002 was a result of completion of work to install environmental compliance equipment at the Centralia plant and a higher proportion of gas-fired plant capacity. Planned maintenance at the Alberta thermal plants increased compared to 2002, which partially offset the increased availability at the Centralia plant and new gas plants. Production increased in 2004 as a result of incremental production from the Mexican and Sarnia plants, which were commissioned during 2003. Production increased in 2003 due to capacity additions from the acquisitions of a 50 per cent interest in CE Gen and the remainder of Vision Quest Windelectric Inc. (Vision Quest); the commencement of commercial operations at the Sarnia, Campeche and Chihuahua plants; and higher production from the Centralia and Poplar Creek plants. The increase was partially offset by the decommission-ing of unit three of the Wabamun plant in November 2002. O P E R AT I N G I N C O M E In 2004, operating income decreased to $478.1 million compared to $561.6 million in 2003 and increased compared to $212.6 million in 2002 as shown below: |
Operating income Dec. 31, 2002 | $ | 212.6 | |
Increased Generation gross margins | 67.0 | ||
Increased CE Gen operating income | 79.5 | ||
2002 Wabamun Arbitration decision | 38.9 | ||
Lower Energy Marketing gross margins | (4.4) | ||
2003 Energy Marketing TCC loss | (33.3) | ||
Increase in operational and administrative costs | (68.0) | ||
Increased depreciation | (17.5) | ||
2003 gain on sale of Sheerness Generating Station | 191.5 | ||
2003 gain on sale of TransAlta Power partnership units | 15.2 | ||
2002 Wabamun impairment charge | 110.0 | ||
2002 turbine order cancellation | 42.5 | ||
2003 turbine impairment | (84.7) | ||
2003 gain on sale of land | 10.5 | ||
2003 Binghamton impairment | (5.6) | ||
Pension over-accrual and performance share ownership plan recovery in 2003 | 10.1 | ||
Other | (2.7) | ||
Operating income Dec. 31, 2003 | $ | 561.6 | |
Increased Generation gross margins | 11.6 | ||
Decreased major maintenance costs and lost earnings due to planned outages | 18.0 | ||
Increase in operational and administrative costs | (8.4) | ||
Increased depreciation | (38.3) | ||
Lower CE Gen operating income | (21.5) | ||
2003 Energy Marketing TCC loss | 33.3 | ||
Increase in provision for California receivable | (22.9) | ||
Pension over-accrual and performance share ownership plan recovery in 2003 | (10.1) | ||
2003 gain on sale of Sheerness Generating Station | (191.5) | ||
Increased gain on sale of TransAlta Power partnership units | 29.6 | ||
2003 turbine impairment | 84.7 | ||
2003 Binghamton impairment | 5.6 | ||
2003 gain on sale of land | (10.5) | ||
2004 gain on sale of Meridian Cogeneration Facility | 17.7 | ||
Other | 19.2 | ||
Operating income Dec. 31, 2004 | $ | 478.1 | |
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In 2004, gross margin increased by $53.2 million compared to the same period in 2003 as a result of the incremental margin from the Mexican plants ($27.3 million), the effect of the Wabamun plant becoming merchant ($43.5 million), and lower lost margin due to planned maintenance ($15.6 million), offset by an increase in the cost of fuel and purchased power due to higher diesel prices and increased overburden removal costs ($42.4 million). In addition, a $33.3 million Transmission Congestion Contracts (TCCs) loss was recognized in the second quarter of 2003. Further discussion of the TCC loss is included in Significant Events in this MD&A. Gross margins increased by $296.8 million in 2003 compared to 2002 as a result of increased production and availability and the $38.9 million Wabamun arbitration decision, which was recorded as a reduction to revenues in 2002. For the year ended Dec. 31, 2004, Operations, Maintenance and Administration (OM&A) increased by $13.4 million ($0.25 per MWh) due in part to incremental operating costs related to the Mexican and Sarnia plants ($14.7 million) offset by decreased planned maintenance ($2.4 million). Additionally, in 2003, OM&A costs were reduced as a result of the reversal of a pension over-accrual and a decrease in expected performance share ownership plan payouts due to market conditions ($10.1 million). In 2003, OM&A increased by $138.8 million ($1.68 per MWh) compared to 2002. Excluding the impact of the CE Gen acquisition, OM&A costs increased by $68.0 million ($0.86 per MWh) due to the commencement of commercial operations at the Sarnia, Campeche and Chihuahua plants and increased planned maintenance at the Alberta Thermal plants. In the year ended Dec. 31, 2004, depreciation expense increased by $38.3 million ($0.70 per MWh) primarily due to incremental depreciation from the Chihuahua, Campeche and Sarnia plants ($18.1 million), increased depreciation at the Ottawa, Mississauga and Windsor-Essex plants ($7.8 million) and the remainder is primarily due to increased capital spending on planned maintenance. Depreciation and amortization increased by $96.0 million ($1.38 per MWh) in 2003 compared to 2002, of which $83.8 million is the result of the CE Gen acquisition. The remaining increase is due to incremental depreciation from the commissioning of the Sarnia, Campeche and Chihuahua plants, substantially offset by the decommissioning of Wabamun unit three and the strengthening of the Canadian dollar compared to the U.S. dollar. D I S C O N T I N U E D O P E R AT I O N S In April 2002, TransAlta’s Transmission operations were sold for proceeds of $820.7 million. The disposal resulted in an after-tax gain on sale of $120.0 million that was recorded in the second and fourth quarters of 2002. During the second quarter of 2004, final working capital adjustments were made to reflect post-closing adjustments and other provisions related to closing costs, which resulted in an additional $9.6 million after-tax gain, bringing the final gain on the sale of the Transmission operations to $129.6 million. E A R N I N G S P E R S H A R E A N D C A S H F L O W Earnings from continuing operations for 2004 were $160.6 million ($0.83 per common share), compared to $234.2 million ($1.26 per common share) for 2003. This variance was due primarily to the $145.8 million after-tax gain on the sale of the Sheerness Generating Station and the $55.4 million after-tax turbine impairment charge in 2003. The increase of $167.4 million in 2003 compared to 2002 was due to these factors, as well as earnings from continuing operations for 2002 including the $11.2 million after-tax gain from the refinanc-ing of foreign operations, the $27.6 million after-tax turbine order cancellation charge, the $71.5 million after-tax Wabamun impairment charge and the $25.2 million after-tax charge resulting from the Wabamun arbitration decision. See Significant Events below for further discussion. In 2004, cash flow from operating activities was $613.4 million, compared to $526.9 million in 2003. The variance was primarily due to improved non-cash operating working capital balances and increased cash earnings. Cash flow from operating activities in 2003 increased by $128.3 million from $398.6 million in 2002. The increase was primarily due to higher earnings and the collection of commodity tax receivables in the U.S. and Mexico (US$79.0 million) in 2003, the settlement of a disputed ancillary services revenue issue with the Balancing Pool of Alberta ($49.9 million) in 2002 the timing of cash tax obligations ($55.6 million) in 2002 and the final installment of 2001 income taxes paid in 2002 ($109.0 million).
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M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 2 7
S I G N I F I C A N T E V E N T S
These consolidated financial results include the following significant events. All gains and losses discussed below are presented as pre-tax (after-tax) amounts, unless otherwise noted.
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Decommissioning of Wabamun Plant
In the fourth quarter of 2002, TransAlta decided to implement a phased decommissioning of the Wabamun facility by removing the 139 MW unit three from service in 2002, and as a result of this decision, decommis-sioned units one and two (62 MW and 57 MW, respectively) on Dec. 31, 2004. The corporation plans to retire unit four (279 MW) in 2010 when its operating license expires. The Power Purchase Arrangement (PPA) for the plant expired on Dec. 31, 2003. Production in 2004 was sold on the spot market. The costs of decommis-sioning will reduce the Asset Retirement Obligation on the balance sheet.
Sale of Meridian Cogeneration Facility
On Dec. 1, 2004, TransAlta completed the sale of its 50 per cent interest in the 220 MW Meridian Cogeneration Facility located in Lloydminster, Saskatchewan to TransAlta Cogeneration, L.P. (TA Cogen) for its fair value of $110.0 million. TA Cogen (owned 50.01 per cent by TransAlta and 49.99 per cent by TransAlta Power) financed the acquisition through the use of $50.0 million of cash on hand, by issuance of $30.0 million of units to each of TransAlta Power and TransAlta Energy Corporation (TEC) and the issue of an advance to TEC for $30.0 million. TransAlta recorded a gain of $17.7 million ($11.5 million) or $0.06 per common share on an after-tax basis.
Sale of TransAlta Power Units
On Dec. 3, 2004, TransAlta sold 7.1 million units of TransAlta Power at $9.00 each for net proceeds of $64.0 million, resulting in a gain of $20.6 million ($13.4 million) including a dilution gain of $11.6 million that arose as a result of the reduction in TransAlta’s ownership of TransAlta Power. These units were the remaining TransAlta Power units that the corporation owned, representing approximately 10 per cent of TransAlta Power’s outstanding units, following expiration of warrants on Aug. 3, 2004. TransAlta Power issued the warrants on July 31, 2003 when purchasing an indirect 25 per cent interest in the Sheerness Generating Station.
Summerview Wind Farm
In the third quarter of 2004, TransAlta commissioned the 68 MW Summerview Wind Farm.
Alberta Distribution and Retail (D&R) Operations
In September 2004, a regulatory decision relating to recovery of certain costs was issued that allowed TransAlta to finalize outstanding items relating to the sale of the D&R operations. Effective Aug. 31, 2000, TransAlta sold its D&R operations for proceeds of $857.3 million, which resulted in an after-tax gain on disposal of $262.4 million. The finalization of the sale did not result in any significant adjustments to the consolidated financial statements.
Gain on Transmission Sale
In June 2004, a settlement was reached to finalize the sale of the Transmission operations. In April 2002, TransAlta’s Transmission operations were sold for proceeds of $820.7 million. The disposal resulted in an after-tax gain on sale of $120.0 million that was recorded in the second and fourth quarters of 2002. During the second quarter of 2004, final working capital adjustments were made to reflect post-closing adjustments and other provisions related to closing costs, which resulted in an additional $9.6 million after-tax gain, bringing the final gain on the sale of the Transmission operations to $129.6 million.
New Zealand Tax Settlement
In June 2004, TransAlta received notice from the New Zealand Inland Revenue of a favourable settlement relating to the 1999 taxation year. As a result, a NZ$8.0 million (Cdn$6.8 million) income tax recovery was recorded in the second quarter of 2004.
Prior Period Regulatory Decision
At Dec. 31, 2000, TransAlta made a provision of US$28.8 million to account for potential refund liabilities relating to energy sales in California. On Dec. 12, 2002, a U.S. Federal Energy Regulatory Commission (FERC) Administrative Law Judge issued proposed findings of fact that recommended TransAlta refund US$9.0 million for electricity sales made to the California Independent System Operator (CAISO) and US$13.0 million for electricity sales made to the California Power Exchange (CALPX). In March 2003, FERC ordered the CAISO to review reference power and gas prices which are used to determine mitigated market clearing prices and refund obligations. On March 17, 2004, the CAISO released its preliminary adjusted prices. Based on these prices, the
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estimated refund liability now owed by TransAlta is US$46.0 million, being US$27.6 million to the CAISO, US$17.9 million to the CALPX and US$0.5 million to the Automated Power Exchange. Therefore, in March 2004, TransAlta recorded an additional pre-tax provision of US$17.2 million (Cdn$22.9 million). The after-tax impact was Cdn$14.9 million. The final adjusted prices were released in October 2004 and were substantially the same as those released on March 17, 2004.
FERC has provided TransAlta with an opportunity to petition for relief from refund obligations. To be successful in such a petition for relief, TransAlta will be required to demonstrate that, as a result of the refund methodology, it has suffered operating losses in respect of California transactions during the refund period. TransAlta has prepared a petition for relief from the refund obligation that may be filed once FERC provides stakeholders with a direction on the filing of such positions. While the outcome of this filing cannot be determined at this time, any such relief would be accounted for only at the time that it is obtained from FERC.
The impact of prior period regulatory decisions relating to prior reporting periods is recorded when the effect of such decisions is known, without adjustment to the financial statements of prior periods.
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Acquisitions
In January 2003, the corporation purchased a 50 per cent interest in CE Gen.Note 4of the audited consolidated financial statements discloses details of the transaction. TransAlta’s share of CE Gen’s results are included in the Generation segment.
In January 2003, TransAlta acquired a 50 per cent interest in EPCOR’s Genesee 3 project. The 450 MW addition to the existing Genesee Generating Station is currently under construction southwest of Edmonton, Alberta, and TransAlta’s share of the project is estimated to cost $379.0 million. Included in the arrangement was an option for EPCOR to purchase a 50 per cent interest in TransAlta’s Sarnia plant that was exercisable until March 31, 2004. EPCOR did not exercise the option.
Equity Offering
In March and April 2003, the corporation issued a total of 17.25 million common shares for gross proceeds of $276.0 million.
Sale of Goldfields Gas Pipeline
In April 2003, TransAlta sold its remaining interest in the Goldfields gas pipeline for proceeds of AUD$24.1 million (Cdn$21.6 million), which approximated book value.
Sale of Head Office Building
On May 9, 2003, TransAlta Utilities Corporation (TAU) sold the Calgary head office building for $65.8 million, which was an agreed-upon value. TransAlta is leasing the property for a term of 20 years.
Energy Marketing Loss on Transmission Congestion Contracts
TransAlta submitted an erroneous bid to the New York Independent System Operator (New York ISO) for May 2003 TCCs. The New York ISO manages New York’s electricity transmission system and TCCs are financial contracts. TransAlta’s computer spreadsheet contained mismatched bids for TCCs due to a clerical error and resulted in TransAlta purchasing more contracts at higher prices than intended. The erroneous bid resulted in a $33.3 million (US$20.0 million) pre-tax loss in May 2003, which was taxed at the statutory rate of 40 per cent.
Asset Impairment Charges
In the third quarter of 2003, following a strategic review and after examining expected market conditions and potential development opportunities against TransAlta’s risk profile, the corporation concluded that the book value of its turbine inventory was unlikely to be fully recovered. As a result, TransAlta recorded an $84.7 million impairment charge ($55.4 million).
The corporation performs an annual review of its property, plant and equipment. As a result of this review, TransAlta recorded a $5.6 million ($3.6 million) impairment charge on the Binghamton plant in the fourth quarter of 2003. The Binghamton plant is a peaker plant that sells electricity to the New York area at spot market rates when such prices exceed its marginal operating costs. Due to generation overcapacity in the Northeastern U.S. and transmission constraints, TransAlta does not expect the plant to operate on a regular basis or at prices that would justify its book value prior to the writedown. The impairment charge reduced the Binghamton plant’s book value to fair value.
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Sale of the Sheerness Generating Station
On July 31, 2003, TransAlta completed the sale of its 50 per cent interest in the two-unit, 756 MW coal-fired Sheerness Generating Station to TA Cogen for $630.0 million. TA Cogen is owned 50.01 per cent by TransAlta and 49.99 per cent by TransAlta Power. TransAlta received cash proceeds of $149.9 million, $315.0 million in TA Cogen units and $165.1 million in TransAlta Power units. As part of the financing and concurrent with the sale, TransAlta Power issued 17.75 million partnership units to TransAlta. Warrants, when exercised, were exchangeable for one TransAlta Power unit at any time until Aug. 3, 2004. Between July 31, 2003 and Aug.3, 2004, 10.4 million warrants were exercised. As the warrants were exercised, TransAlta sold TransAlta Power units back to TransAlta Power for $9.30 per unit, reducing its ownership interest in TransAlta Power. As a result of the exercise of the warrants and subsequent sale of remaining units held by TransAlta in the fourth quarter of 2004, TransAlta has reduced its ownership interest in TransAlta Power to 0.01 per cent held by TransAlta Power Ltd., a wholly-owned subsidiary of TransAlta and the general partner of TransAlta Power, as at Dec. 31, 2004.
In connection with the sale of the Sheerness Generating Station, the obligation for TransAlta to purchase all of TransAlta Power’s interest in TA Cogen on Dec. 31, 2018 that arose on the sale of power generation assets to TA Cogen in 1998 was eliminated; therefore the deferred gain of approximately $119.8 million was recognized in earnings. In addition, the management agreements between TransAlta and TransAlta Power and TA Cogen were amended to remove the mechanism for the deferral of the management fees and remove the obligation for TransAlta Power and TA Cogen to pay management fees to TransAlta in the future. As consideration for the removal of these terms, TransAlta received $1.0 million from TransAlta Power and $5.0 million from TA Cogen in the third quarter of 2003.
As a result of the sale, TransAlta realized a gain on sale of $191.5 million ($145.8 million) recorded in the third quarter of 2003, which included the realization of the approximate $119.8 million 1998 deferred gain. Proceeds from the sale of the Sheerness Generating Station were used to repay debt.
Further gains resulting from the dilution of TransAlta’s ownership in TransAlta Power on exercise of the warrants and on the subsequent sale of units totalled $60.0 million, of which $44.8 million ($29.1 million) was recognized in 2004 and $15.2 million ($10.1 million) in 2003.
Investment Write Down
On an annual basis, TransAlta reviews the valuation of its long-term equity investments. As a result of this review, in the fourth quarter of 2003, the corporation recorded a $6.2 million ($4.1 million) charge to recognize an other than temporary decline in fair value. The charge is included in OM&A expenses.
Sale of Seebe Land
On Dec. 31, 2003, TransAlta sold 539 acres of undeveloped land at Seebe, Alberta for $11.0 million. The corporation recognized a gain on sale of $10.5 million ($8.6 million).
2 0 0 2
Centennial Project
In February 2002, the EUB approved the previously announced Centennial project, which is a 900 MW merchant expansion at the Keephills site. The first phase of the project (Centennial 1) is now part of the arrangement with EPCOR and the two corporations are jointly proceeding with the development phase of the project.
In the fourth quarter of 2004, the corporation announced that it is asking the EUB to amend its 900-MW Centennial permit to allow for the construction of a smaller 450 MW plant using more advanced supercritical technology.
Prior Period Regulatory Decisions
In April 2002, the EUB rendered a negative decision of $3.3 million ($2.1 million) with respect to TransAlta’s hydro bidding strategy in 2000.
Wabamun Arbitration Decision
In May 2002, the corporation received the arbitrators’ decision with respect to the Wabamun outage. As a result of the decision, the corporation was required to pay $38.9 million ($25.2 million), which was recorded as a reduction of revenue.
Ancillary Services Revenue Settlement
In July 2002, a dispute with the Balancing Pool of Alberta in respect of the allocation of hydro ancillary services deferred revenue under the PPAs was resolved. TransAlta repaid $49.9 million received in advance from the
3 0 Tr a n s A l t a C o r p o r a t i o n A R / 0 4
Balancing Pool. The settlement had no earnings impact as the corporation had not previously recognized the amount as revenue.
Refinancing of Foreign Operations
During the third quarter of 2002, TransAlta restructured the financing of certain of its foreign operations. As a result, the corporation was able to record the benefit of previously unrecognized foreign tax loss carryfor-ward balances. This restructuring contributed $11.2 million to earnings as reduced income tax expense in the third quarter of 2002.
Turbine Order Cancellation
In the fourth quarter of 2002, the corporation cancelled orders for four turbines and recorded a cancellation charge of $42.5 million ($27.6 million). The costs consisted solely of progress payments made to the date of the contract termination.
Purchase of Vision Quest
In the fourth quarter of 2002, TransAlta purchased the remaining interest in Vision Quest. The transaction increased the corporation’s total investment in the wind power company to $68.8 million. At the time of acquisition, Vision Quest operated 124 wind turbines with 119 MW of gross generating capacity in operation (82 MW net ownership interest). Vision Quest’s financial results are included in Generation’s results for segmented reporting purposes.
N E W A C C O U N T I N G S TA N D A R D S
The Canadian Institute of Chartered Accountants (CICA) established a new standard on the disposal of long-lived assets and discontinued operations. This standard became effective May 1, 2003; however, TransAlta early adopted the standard on Jan. 1, 2003 with retroactive restatement. The standard requires that a long-lived asset to be disposed of other than by sale shall continue to be classified as held and used until it is disposed of. Certain criteria must be met before a long-lived asset can be classified as held for sale. The standard also defines discontinued operations more broadly than previously and prohibits the inclusion of future operating losses in a loss recognized upon classification of a long-lived asset as held for sale. The impact of adopting this standard was not material to the consolidated financial statements.
In the fourth quarter of 2003, in response to changes in accounting standards in the U.S. with respect to derivative instruments not held for trading, the corporation adopted a policy that all gains and losses on real-time physical trading contracts be shown gross in the statements of earnings. Prior period amounts have been restated.
On Jan. 1, 2004, TransAlta early adopted the amended CICA standard on the presentation of liabilities and equity. The standard addresses the situation in which an entity has a contractual obligation of a fixed amount or an amount that fluctuates in part or in full in response to changes in a variable other than the market price of the entity’s own equity instruments, but the entity must, or can, settle the obligation by delivery of its own equity instruments (the number of which depends on the amount of the obligation). Such an obligation is a financial liability of the entity. TransAlta has presented the corporation’s preferred securities as financial liabilities on the consolidated balance sheets. Preferred securities distributions are included in interest expense on the consolidated statements of earnings(Note 11 to the consolidated financial statements)and therefore included as a deduction in arriving at net earnings. This change in accounting policy was recorded retroactively with restatement and, as a result, preferred securities distributions, net of tax, have been reduced to nil in each of 2002, 2003 and 2004, net interest expense for the year ended Dec. 31, 2004 was increased by $44.5 million (2003 – $36.8 million, 2002 – $34.9 million), and income tax expense for the year ended Dec. 31, 2004 was decreased by $15.0 million (2003 – $13.8 million, 2002 – $14.0 million). Preferred securities have been increased to $475.0 million from $450.8 million as at Dec. 31, 2003.
Effective Jan. 1, 2004, the corporation has prospectively presented employee share purchase plan loans as a deduction from shareholders’ equity. The impact of this new accounting treatment is not material to the consolidated financial statements.
In March 2004, the U.S. Financial Accounting Standards Board (FASB) Emerging Issues Task Force (EITF) reached a consensus on EITF Issue No. 04-02,Whether Mineral Rights are Tangible or Intangible Assets,that mineral rights, as defined in the Issue, are tangible assets. As a result of this decision, TransAlta accounts for coal rights under both Canadian and U.S. GAAP as tangible assets. Prior period amounts have been reclassified from intangible assets to tangible assets (Dec. 31, 2003 – $58.5 million). There was no effect on net earnings as a result of the reclassification.
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 3 1
O U T L O O K
The key factors affecting the financial results in 2005 are the megawatt capacity in place, the availability of and production from generating assets, the margins applicable to non-contracted production, the costs of production and the volumes traded and margins achieved on Energy Marketing activities.
The following factors will be influenced by, but not limited to, certain risks and uncertainties. For further discussion, see Risk Factors and Risk Management in this MD&A.
Production, Availability and Capacity
Generating capacity is expected to increase in 2005 due to the completion of the 225 MW Genesee 3 project, partially offset by the decommissioning of units one and two of the Wabamun plant on Dec. 31, 2004 (62 MW and 57 MW, respectively).
Production is expected to increase in 2005 due to the addition of Genesee 3.
The existing contracts have remaining terms ranging from one to 30 years. Contracted production, as a percentage of potential production from existing assets and assets currently under construction at Dec. 31, 2004, is shown for the next five years in the chart to the left.
If certain plants do not meet the availability or production targets specified in the PPAs or other long-term contracts, then the corporation must either compensate the purchaser for the loss in the availability of production or suffer a reduction in electrical or capacity payments. Consequently, an extended outage could have a material adverse effect on the business, financial condition, results of operations or cash flows of the corporation.
Production and gross margins from the merchant gas plants are subject to the changes in spark spreads discussed in the power prices section. TransAlta has not entered into fixed commodity agreements for gas for these merchant plants as gas will be purchased coincident with spot market spark spreads being adequate to produce and sell electricity.
Planned Maintenance
During 2005, TransAlta expects to spend between $210 million and $235 million on planned maintenance as outlined in the following table (excluding CE Gen):
Year ended Dec. 31, 2005 | Coal | Gas | Hydro | Total | ||||||||
Capitalized | $ | 70-80 | $ | 65-70 | $ | 10 | $ | 145-160 | ||||
Expensed | 55-65 | 10 | – | 65-75 | ||||||||
$ | 125-145 | $ | 75-80 | $ | 10 | $ | 210-235 | |||||
GWh lost | 2,300 | 600 | – | 2,900 | ||||||||
TransAlta expects to lose approximately 2,900 GWh of production due to planned maintenance in 2005.
Power Prices
TransAlta is only affected by short-term market prices in certain markets. Electricity spot prices for 2005 are expected to be comparable to those realized in 2004 in all markets. Alberta’s spot power prices should soften slightly as new supply is only partially offset by anticipated strength in gas prices in 2005. Mid-Columbia, on the other hand, may see power prices increase slightly on natural gas price strength, assuming normal to below normal hydro conditions. Ontario power prices are expected to remain steady year over year. With higher average gas prices anticipated in 2005, spark spreads are expected to compress in Ontario and Alberta with Mid-Columbia generally unchanged.
Exposure to volatility in electricity prices and spark spreads is substantially mitigated through firm-price, long-term electricity sales contracts. Exposure to volatility in gas prices is partially mitigated by the flow-through of the costs of natural gas to customers in some of these contracts and the existence of price caps in certain natural gas supply contracts. For 2005, approximately 87 per cent of output is contracted, a significant portion of which relates to the Alberta PPAs, which are based on achieving specified availability rates. The corporation will continue to focus on maximizing margins from these contracts.
In December 2004, the Ontario government passed Bill 100 to reform Ontario’s electricity sector. The Bill includes a combination of a regulated and competitive market, targets for energy conservation and the use of renewable energy, providing consumer price stability and the creation of a new Ontario Power Authority to ensure an adequate long-term supply of electricity. The future operating results of TransAlta’s Sarnia Cogeneration plant may be significantly affected, depending on the legislation being passed and the resultant changes in
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merchant pricing or the availability of stable long-term contracts for electricity producers. At this time, TransAlta cannot reasonably assess the impact of the proposed changes to the structure of the Ontario energy sector and its impact on Sarnia’s future operating results.
Costs of Production
Fluctuations in the cost of coal are minimized through ownership of reserves in Alberta and the State of Washington and by diversifying into wind generation, which has virtually no variable costs of production. OM&A costs per MWh fluctuate by quarter and are dependent on the timing and nature of maintenance activities. OM&A costs per MWh in 2005 are expected to increase slightly over 2004.
Energy Marketing
Energy Marketing’s trading activities are focused on real-time and short-term forward markets. Short-term forward markets show indications of increased volatility in the North American natural gas market. TransAlta will continue to prudently manage its risk profile utilizing value at risk and other measures.
Our objective is for proprietary trading to contribute between $20 million and $40 million in annual operating income.
Net Interest Expense
Net interest expense is expected to increase in 2005 as a result of the reduction of capitalized interest due to the completion of construction of the Genesee 3 plant and the Summerview Wind Farm. During 2004, the corporation capitalized interest of $20.0 million as a result of the construction activity during the year.
Income Tax Rate
Income tax rates in 2005 are expected to be consistent with 2004 levels. Assuming a similar geographic distribution of earnings and no material changes in tax rates, the corporation anticipates an effective tax rate for 2005 of approximately 25 per cent.
Non-controlling Interests
Non-controlling interests are expected to increase in 2005 as a result of the reduction in TransAlta’s ownership in TransAlta Power and in the Meridian Cogeneration Facility.
Capital Expenditures
Capital expenditures for 2005 are expected to be approximately $360 million to $375 million, of which approximately $150 million is expected to be spent on major maintenance (excluding CE Gen), $100 million is expected to be spent on the Alberta and Centralia mines and $50 million is expected to be spent to complete the Genesee 3 project. The remainder is expected to be spent at CE Gen and on productivity related investments. Financing for these expenditures is expected to be provided by cash flow from operations.
Exposure to Fluctuations in Foreign Currencies
TransAlta will continue to offset foreign denominated assets with foreign denominated liabilities. TransAlta also has foreign currency expenses, primarily interest charges that offset foreign currency revenues. This strategy minimizes the impact on TransAlta of the recent appreciation in the Canadian dollar against the U.S. dollar.
Cash Requirements
In 2005, cash will be provided by a combination of cash flow from operations and utilization of various credit facilities. Cash will be required for maintenance, additions to property, plant and equipment, dividend payments and repayment of short-term and maturing senior debt.
Climate Change
On Dec. 16, 2002, the Canadian government ratified the Kyoto Protocol, which came into effect on Feb. 16, 2005. It is not expected to have an impact on TransAlta’s U.S., Mexican or Australian operations. In Canada, TransAlta is not yet able to estimate the full impact the Protocol will have on its operations, as the Canadian government has not established the regulatory requirements. However, the PPAs for TransAlta’s coal-fired plants in Alberta contain ‘Change of Law’ provisions that should provide for the recovery of compliance costs from the PPA customers.
TransAlta continues to take measured action to mitigate future climate change costs. The corporation is building a portfolio of emission offsets for its merchant plants as part of its response to climate change. In 2004, TransAlta completed the first Canadian purchase of certified emission reductions under the Kyoto mechanisms. As a member of the Canadian Clean Power Coalition, TransAlta, along with its peers, is exploring other means to reduce greenhouse gas emissions, including the development of clean coal technology. TransAlta continues to grow its renewable energy portfolio, reduce its emissions intensity and diversify its fuel mix.
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 3 3
S E G M E N T E D B U S I N E S S R E S U LT S
GenerationOwns and operates hydro, wind, geothermal, gas- and coal-fired plants and related mining operations in Canada, the U.S., Mexico and Australia. At Dec. 31, 2004, Generation had 8,806 MW of gross generating capacity in operation (8,337 MW net ownership interest) and 225 MW under construction.
For the year ended Dec. 31, 2004, availability decreased to 89.1 per cent from 90.6 per cent in 2003, primarily due to unplanned outages at the Mexico plants in the first quarter and higher planned maintenance at the Sheerness and Centralia plants in the second quarter. In 2003, availability increased to 90.6 per cent from 88.4 per cent in 2002 due to higher availability at the Centralia and Poplar Creek plants and the addition of the new gas plants.
The results of the Generation segment were as follows:
2004 | 2003 | 2002 | ||||||||||||||||
Year ended Dec. 31 | Total | Per MWh | Total | Per MWh | Total | Per MWh | ||||||||||||
Revenues | $ | 2,593.8 | $ | 47.54 | $ | 2,412.2 | $ | 45.40 | $ | 1,674.9 | $ | 35.51 | ||||||
Fuel and purchased power | (1,231.3) | (22.57) | (1,067.4) | (20.09) | (664.6) | (14.09) | ||||||||||||
Gross margin | 1,362.5 | 24.97 | 1,344.8 | 25.31 | 1,010.3 | 21.42 | ||||||||||||
Operations, maintenance and administration | 501.2 | 9.19 | 480.0 | 9.03 | 346.7 | 7.35 | ||||||||||||
Depreciation and amortization | 363.3 | 6.66 | 321.6 | 6.05 | 220.3 | 4.67 | ||||||||||||
Taxes, other than income taxes | 20.8 | 0.38 | 23.1 | 0.43 | 27.3 | 0.58 | ||||||||||||
Operating expenses | 885.3 | 16.23 | 824.7 | 15.51 | 594.3 | 12.60 | ||||||||||||
Gain on sale of Sheerness Generating Station | – | – | 191.5 | 3.60 | – | – | ||||||||||||
Gain on sale of TransAlta Power partnership units | 44.8 | 0.82 | 15.2 | 0.29 | – | – | ||||||||||||
Gain on sale of Meridian Cogeneration Facility | 17.7 | 0.32 | – | – | – | – | ||||||||||||
Gain on sale of Seebe land | – | – | 10.5 | 0.20 | – | – | ||||||||||||
Asset impairment charges | – | – | (90.3) | (1.70) | (152.5) | (3.23) | ||||||||||||
Prior period regulatory decision | – | – | – | – | (3.3) | (0.07) | ||||||||||||
Operating income before corporate allocations | 539.7 | 9.88 | 647.0 | 12.19 | 260.2 | 5.52 | ||||||||||||
Corporate allocations | 69.7 | 1.28 | 69.9 | 1.32 | 70.6 | 1.50 | ||||||||||||
Operating income | $ | 470.0 | $ | 8.60 | $ | 577.1 | $ | 10.87 | $ | 189.6 | $ | 4.02 | ||||||
For the year ended Dec. 31, 2004, 84 per cent of total production was subject to contracted prices (2003 –91 per cent, 2002 – 93 per cent), with the remaining production subject to market pricing. Revenues received under contractual arrangements are not subject to short-term fluctuations in the spot price for electricity.
Generation’s revenues are derived from the production of electricity and steam as well as ancillary services such as system support. In 2004, gas- and coal-fired facilities had exposure to market fluctuations in energy commodity prices representing four per cent and 26 per cent of TransAlta’s total generating capacity, respectively. The corporation closely monitors the risks associated with these commodity price changes on its future operations and, where appropriate, uses various physical and financial instruments to hedge its assets and operations from such price risk. These contracts are designated as effective hedge positions of future cash flows or fair values of the output and production of its owned assets. Under Canadian GAAP, settlement accounting is used for transactions that qualify for hedge accounting. Under U.S. GAAP, hedging activities are accounted for in accordance with FASB Statement 133.
TransAlta’s results are partly seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are ordinarily incurred in the second and third quarters when electricity prices are expected to be lower as electricity prices generally increase in the winter months in the Canadian market. Margins are also typically impacted in the second quarter due to the volume of hydro production resulting from spring runoff and rainfall in the Canadian and U.S. markets. TransAlta’s results reflect the completion, acquisition and disposition of plants and facilities throughout 2003 and 2004 as described previously within this MD&A.
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TransAlta’s electricity and steam production revenues are generated from the following revenue streams: Alberta Power Purchase Arrangementsare long-term arrangements that apply to the previously regulated Alberta generation plants. All of TransAlta’s Alberta coal-fired and hydroelectric facilities operated under PPAs during 2004, except for the Wabamun plant. The PPA for the Wabamun plant expired on Dec. 31, 2003. Under the terms of a PPA, a single customer has the rights to the entire production of a plant or unit for the length of the PPA. PPAs established committed capacity and electrical energy generation requirements and availability targets to be achieved by each coal-fired plant, energy and ancillary services obligations for the hydroelectric plants, and the pricing formula at which capacity and power would be supplied. The corporation bears the risk or retains the benefit of volume variances (except for those arising from events considered to be force majeure, in the case of the coal-fired plants), and any change in costs required to maintain and operate the facilities. A component of the PPA capacity payment represents fixed operating, maintenance and fuel costs and is escalated annually based on certain indices published by Statistics Canada. The component of the capacity payment representing debt interest and a return on equity invested is subject to changes in the Canadian long-term bond rate. Under the PPAs, the corporation earns monthly capacity revenues, which are designed to recover fixed costs and provide a return on capital for the plants and mines. The corporation also earns energy payments for the recovery of predetermined variable costs of producing energy, an incentive/penalty for achieving above/below the targeted availability and an excess energy payment for power production above committed capacity. The corporation’s hydroelectric facilities are not contracted on a facility-by-facility basis; rather, facilities are aggregated in a single Alberta PPA that provides for energy and ancillary services obligations based on hourly targets. These targeted amounts are met by TransAlta through physical delivery or third-party purchases. Long-term Contractsare similar to PPAs. TransAlta defines a long-term contract as having an original term between 10 and 25 years. Long-term contracts are typically for gas-fired cogeneration plants and have between one and four customers per plant. Revenues are derived from payments for capacity and/or the production of electrical energy and steam. Merchantrevenue is derived from the sale of production only, with multiple customers per plant. Production is sold via: medium-term contract sales (typically three to seven years); short-term asset-backed trading; and spot or short-term (less than one year) forward markets. CE Genearns revenues from 10 geothermal plants (164 MW) and three gas-fired facilities (215 MW). Eight of the geothermal plants sell their output under long-term contracts expiring between 2016 and 2035. One facility is partially contracted while the remaining facility sells its output on the spot market but has an option to sell output under a 35-year contract based on market prices. The gas-fired facilities sell their output under fixed-price contracts ranging from two to 30 years in length, with expiration dates of 2005, 2009 and 2024. All three facilities have gas supply arrangements in place for the duration of the electricity sales contracts. TransAlta’s production volumes, electricity and steam production revenues and fuel and purchased power costs are presented below: |
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Fuel & | ||||||||||||||||||||
Fuel & | purchased | Gross | ||||||||||||||||||
Production | purchased | Gross | Revenue | power | margin | |||||||||||||||
Year ended Dec. 31, 2004 | (GWh) | Revenue | power | margin | per MWh | per MWh | per MWh | |||||||||||||
Alberta PPAs | 25,836 | $ | 679.2 | $ | 187.9 | $ | 491.3 | $ | 26.29 | $ | 7.27 | $ | 19.02 | |||||||
Long-term contracts | 10,347 | 834.0 | 541.5 | 292.5 | 80.60 | 52.33 | 28.27 | |||||||||||||
Merchant | 15,676 | 799.5 | 435.2 | 364.3 | 51.00 | 27.76 | 23.24 | |||||||||||||
CE Gen | 2,701 | 281.1 | 66.7 | 214.4 | 104.07 | 24.69 | 79.38 | |||||||||||||
54,560 | $ | 2,593.8 | $ | 1,231.3 | $ | 1,362.5 | $ | 47.54 | $ | 22.57 | $ | 24.97 | ||||||||
Fuel & | ||||||||||||||||||||
Fuel & | purchased | Gross | ||||||||||||||||||
Production | purchased | Gross | Revenue | power | margin | |||||||||||||||
Year ended Dec. 31, 2003 | (GWh) | Revenue | power | margin | per MWh | per MWh | per MWh | |||||||||||||
Alberta PPAs | 28,295 | $ | 758.8 | $ | 191.3 | $ | 567.5 | $ | 26.82 | $ | 6.76 | $ | 20.06 | |||||||
Long-term contracts | 8,538 | 660.2 | 400.8 | 259.4 | 77.32 | 46.94 | 30.38 | |||||||||||||
Merchant | 13,683 | 684.2 | 394.9 | 289.3 | 50.00 | 28.86 | 21.14 | |||||||||||||
CE Gen | 2,618 | 309.0 | 80.4 | 228.6 | 118.03 | 30.71 | 87.32 | |||||||||||||
53,134 | $ | 2,412.2 | $ | 1,067.4 | $ | 1,344.8 | $ | 45.40 | $ | 20.09 | $ | 25.31 | ||||||||
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 3 5
Fuel & | ||||||||||||||||||||
Fuel & | purchased | Gross | ||||||||||||||||||
Production | purchased | Gross | Revenue | power | margin | |||||||||||||||
Year ended Dec. 31, 2002 | (GWh) | Revenue | power | margin | per MWh | per MWh | per MWh | |||||||||||||
Alberta PPAs | 29,792 | $ | 761.6 | $ | 175.4 | $ | 586.2 | $ | 25.56 | $ | 5.89 | $ | 19.68 | |||||||
Long-term contracts | 6,157 | 364.8 | 165.9 | 198.9 | 59.25 | 26.94 | 32.29 | |||||||||||||
Merchant1 | 11,223 | 587.4 | 323.3 | 264.1 | 49.14 | 27.05 | 22.09 | |||||||||||||
Wabamun arbitration decision | – | (38.9) | – | (38.9) | – | – | – | |||||||||||||
47,172 | $ | 1,674.9 | $ | 664.6 | $ | 1,010.3 | $ | 35.51 | $ | 14.09 | $ | 21.41 | ||||||||
1 Revenue per MWh and fuel and purchased power per MWh includes actual production volumes and economic dispatch volumes purchased (731 GWh).
Activities in 2004 for the Wabamun plant are now classified as merchant as production from the plant is being sold in the open market. The PPA for the Wabamun plant expired on Dec. 31, 2003. Production for the year ended Dec. 31, 2004 decreased by 2,459 GWh compared to 2003 primarily due to the Wabamun plant now being classified as merchant (2,940 GWh) and higher unplanned outages at the remaining Alberta Thermal plants (168 GWh) partially offset by reduced planned maintenance (642 GWh). In 2003, production decreased by 1,497 GWh, compared to 2002 as a result of increased planned maintenance at the Alberta Thermal plants and the decommissioning of unit three of the Wabamun plant in November 2002. Revenues for the year ended Dec. 31, 2004 decreased by $79.6 million compared to the same period in 2003 due to the Wabamun plant now being classified as merchant ($92.2 million) and by higher unplanned outages ($34.2 million) partially offset by reduced penalties related to planned maintenance at the remaining Alberta Thermal plants ($53.0 million). Revenues per MWh were consistent with 2003 on a year-over-year basis. In 2003, revenues increased by $1.26 per MWh compared to 2002 due to incentives earned from exceeding the availability targets in the PPAs. For the year ended Dec. 31, 2004, fuel costs increased by $0.51 per MWh compared to the same period in 2003 due to higher diesel prices, increased overburden removal costs and decreased coal volumes. In 2003, fuel costs increased by $0.87 per MWh compared to 2002 due to increased commodity prices and higher planned maintenance costs at the coal mines in 2003. Substantially all of the coal used for production under Alberta PPAs is from coal reserves owned by TransAlta. Long-term Contracts In the year ended Dec. 31, 2004, production increased by 1,809 GWh compared to the same period in 2003 primarily as a result of the incremental production at the Chihuahua and Campeche plants (1,709 GWh), as these plants were commissioned during 2003. Production increased by 2,381 GWh in 2003 compared to the same period in 2002 primarily due to increased production from the Sarnia plant, the acquisition of Vision Quest and the commencement of commercial operations at the Campeche and Chihuahua plants. Revenues increased by $3.28 per MWh in 2004 compared to 2003 primarily due to increased natural gas costs which were passed on to the customer. Fuel and purchased power increased by $5.39 per MWh due to higher market prices for natural gas. Revenues increased by $18.07 per MWh in 2003 compared to 2002. The increase is due in part to $102.9 million ($12.05 per MWh) of incremental steam revenues earned from the Sarnia plant in 2003. Revenues also increased as a result of increased natural gas prices. In 2003, 71 per cent of natural gas prices flowed through to customers and were therefore recovered through revenues. Fuel and purchased power increased by $20.00 per MWh in 2003 compared to 2002 primarily due to higher heat rates at Sarnia, higher natural gas market prices and the cost of the gas used for steam production. For the year ended Dec. 31, 2004, gross margin decreased by $2.11 per MWh compared to the same period of 2003 primarily due to the impact of the incremental production from the Mexican plants, which have lower margins than other long-term contracts. Gross margin per MWh decreased by $1.91 per MWh in 2003 compared to 2002. This decrease is due to higher natural gas prices and the commencement of commercial operations at the Sarnia, Campeche and Chihuahua plants. Merchant Production In 2004, electricity spot prices in the Alberta and Ontario markets decreased while the Mid-Columbia price increased compared to 2003. Spark spreads decreased in both Alberta and the Ontario markets, but increased in the Pacific Northwest market.
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In 2003, electricity spot prices increased over 2002 prices. The Ontario market was regulated until May 2002. Spark spreads increased in both Alberta and the Pacific Northwest markets, but decreased in Ontario. For the year ended Dec. 31, 2004, merchant production was 15,676 GWh, of which 6,718 GWh was contracted. For the same period in 2003, merchant production was 13,683 GWh, of which 8,996 GWh was contracted. The increase in merchant production was due to the sale of uncontracted production from the Wabamun plant and incremental production from Sarnia in the first quarter, partially offset by decreased production at Centralia and lower dispatching from the merchant gas plants. For 2002, merchant production was 11,223 GWh, of which 8,020 GWh was contracted. At certain times during 2002, when the market price of electricity was lower than the variable costs of production at certain plants, the corporation reduced production at these plants and purchased electricity from the market to fulfill contractual obligations (economic dispatch). The increase in production in 2003 reflects increased production from the Sarnia, Centralia and Centralia Gas plants as well as the 731 GWh of economic dispatch that occurred in 2002. In 2004, merchant revenues increased by $115.3 million, fuel and purchased power increased by $40.3 million and gross margins increased by $75.0 million compared to the same period in 2003. These gross margin increases were due to incremental production from the Wabamun plant ($95.6 million) partially offset by lower production and shrinking spark spreads at Centralia ($27.0 million) and Poplar Creek ($8.0 million). On a per MWh basis, merchant revenues increased by $1.00 per MWh while fuel and purchased power decreased by $1.10 compared to the same period in 2003. In 2003, merchant revenues increased by $0.86 per MWh compared to 2002 as a result of higher electricity spot prices. In 2003, fuel and purchased power increased by $1.81 per MWh as a result of increased natural gas prices. Gross margins decreased by $0.95 per MWh in 2003 compared to 2002 due to increased power prices, substantially offset by increased natural gas costs and the strengthening of the Canadian dollar compared to the U.S. dollar. CE Gen TransAlta’s share of CE Gen’s production for 2004 increased by 83 GWh compared to 2003. This was the result of increased availability due to reduced planned maintenance and increased production at Imperial Valley, partially offset by decreased production at the Power Resources facility following the expiration of the long-term contract in September 2003. In 2004, revenues decreased by $13.96 per MWh compared to the same period in 2003 due to the expiration of the Power Resources facility’s long-term contract and the strengthening of the Canadian dollar compared to the U.S. dollar. In 2004, fuel and purchased power decreased by $6.02 per MWh compared to the same period in 2003 primarily due to the gas remarketing arrangement at the Saranac project in the first quarter of 2004 and the strengthening of the Canadian dollar compared to the U.S. dollar, partially offset by increased fuel prices at the Yuma and Saranac facilities in 2004. From the date of acquisition on Jan. 29, 2003 to Dec. 31, 2003, CE Gen production was 2,618 GWh, revenue was $118.03 per MWh and fuel and purchased power was $30.71 per MWh. Operations, Maintenance and Administration Expense For the year ended Dec. 31, 2004, OM&A increased by $21.2 million ($0.16 per MWh) due in part to incremental operating costs related to the Mexican and Sarnia plants ($14.7 million). Additionally, in 2003, OM&A costs were reduced as a result of the reversal of a pension over-accrual and a decrease in expected performance share ownership plan payouts due to market conditions ($10.1 million). In 2003, OM&A increased by $133.3 million ($1.68 per MWh) compared to 2002. Excluding the impact of the CE Gen acquisition, OM&A costs increased by $68.0 million ($0.86 per MWh) due to the commencement of commercial operations at the Sarnia, Campeche and Chihuahua plants and increased planned maintenance at the Alberta Thermal plants. Planned Maintenance The table below shows the amount of planned maintenance capitalized and expensed, excluding CE Gen:
| |
2004 | 2003 | 2002 | |||||||
Capitalized | $ | 99.1 | $ | 35.2 | $ | 102.1 | |||
Expensed | 74.7 | 77.3 | 46.2 | ||||||
$ | 173.8 | $ | 112.5 | $ | 148.3 | ||||
In 2004, 2,587 GWh of production were lost due to planned maintenance compared to 2,198 GWh lost in 2003 and 2,030 GWh lost in 2002.
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 3 7
In 2004, capitalized maintenance increased by $63.9 million while operating maintenance decreased by $2.6 million as compared to the same period in 2003 due to spending on capital replacement activities rather than repair activities in coal outages ($48.8 million) and gas outages ($12.0 million), with no comparable amounts in 2003 for gas outages due to recent additions to the gas fleet. In 2003, capitalized maintenance decreased by $66.9 million while operating maintenance increased by $31.1 million as compared to the same period in 2002, as the majority of maintenance activity in 2003 related to repairs to existing equipment rather than replacement activities. Depreciation and Amortization In 2004, depreciation expense increased by $41.7 million ($0.61 per MWh) primarily due to incremental depreciation from the Chihuahua, Campeche and Sarnia plants ($18.1 million), increased depreciation from CE Gen ($5.4 million), increased depreciation of the Ottawa, Mississauga and Windsor-Essex plants ($7.8 million) and increased capital spending on planned maintenance. Depreciation and amortization increased by $101.3 million ($1.38 per MWh) in 2003 compared to 2002, of which $83.8 million is the result of the CE Gen acquisition. The remaining increase is due to incremental depreciation from the commissioning of the Sarnia, Campeche and Chihuahua plants, substantially offset by the decom-missioning of Wabamun unit three and the strengthening of the Canadian dollar compared to the U.S. dollar. Taxes Other than Income Taxes In 2004, taxes other than income taxes were consistent with both 2003 and 2002. Energy MarketingDerives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives not supported by TransAlta-owned generation assets. Energy Marketing also utilizes contracts of various durations for the forward sales of electricity and purchases of natural gas and transmission capacity to effectively manage available generating capacity and fuel and transmission needs on behalf of Generation. These results are included in the Generation segment. Key performance indicators for Energy Marketing include trading volumes, margins and value at risk (VAR). Energy Marketing uses commodity derivatives to manage risk, earn trading revenue and gain market information. The portfolio consists of physical and financial derivative instruments including forwards, swaps, futures and options in various commodities. These contracts meet the definition of trading activities and have been accounted for using fair values for both Canadian and U.S. GAAP. Changes in the fair values of the portfolio are recognized in income in the period they occur. In compliance with FASB EITF 03-11,Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposesas defined in Issue No. 02-3, TransAlta has concluded that energy trading contracts settled in the real-time physical markets meet the definition of derivative contracts held for delivery and therefore results of these contracts are reported on a gross basis (trading revenues and trading purchases are shown separately) in the consolidated statement of earnings. The results of the Energy Marketing segment are as follows:
| |
Year ended Dec. 31 | 2004 | 2003 | 2002 | ||||||
Revenues | $ | 244.5 | $ | 108.7 | $ | 140.0 | |||
Trading purchases | (197.7) | (97.4) | (91.0) | ||||||
Gross margin | 46.8 | 11.3 | 49.0 | ||||||
Operations, maintenance and administration | 5.3 | 14.9 | 15.1 | ||||||
Depreciation and amortization | 2.0 | 3.1 | 2.5 | ||||||
Taxes other than income taxes | – | – | 0.1 | ||||||
Prior period regulatory decision | 22.9 | – | – | ||||||
Operating income before corporate allocations | 16.6 | (6.7) | 31.3 | ||||||
Corporate allocations | 8.5 | 8.8 | 8.3 | ||||||
Operating income | $ | 8.1 | $ | (15.5) | $ | 23.0 | |||
3 8 Tr a n s A l t a C o r p o r a t i o n A R / 0 4
Gross margin increased by $35.5 million in 2004 compared to the same period in 2003. In the second quarter of 2003, Energy Marketing realized a $33.3 million (US$20.0 million) pre-tax loss on TCCs in the New York area as discussed in the Significant Events section in this MD&A. The remaining increase of $2.2 million for the year ended Dec. 31, 2004 is the result of varying market opportunities across all regions. Purchases for energy trading contracts settled in the real-time physical markets for the year ended Dec. 31, 2004 increased by $100.3 million relative to 2003. The increase is primarily the result of activity relative to an energy services agreement involving purchasing power on behalf of a customer to service retail load. Gross margin decreased by $37.7 million in 2003 compared to 2002 mainly due to the loss on TCCs in the New York area as discussed above. During the third quarter of 2003, Energy Marketing re-evaluated trading strategies and consolidated the Annapolis trading office in Calgary. The closure of the Annapolis office and changing market opportunities in Alberta resulted in fewer volumes being traded and settled in the remainder of 2003. OM&A costs for 2004 decreased $9.6 million relative to the same period in 2003. Consolidation of the Annapolis trading office with Calgary occurred in the fourth quarter of 2003, incurring $1.1 million of direct severance and exit costs. The consolidation resulted in lower staff levels and associated savings in general spending activities in 2004. OM&A costs for 2003 included severance and exit costs as noted above and were consistent with 2002. Depreciation and amortization for 2004 was $1.1 million lower than the same period in 2003 due to closure of the Annapolis office and the resulting asset disposals in 2003. Depreciation and amortization for 2003 was consistent with 2002. VAR is a measure to manage earnings exposure for Energy Marketing activities. The average daily VAR in fiscal 2004 was approximately $3.8 million compared to $3.6 million in 2003. See additional discussion under commodity price risk in Risk Factors and Risk Management. At Dec. 31, 2004, TransAlta had a US$51.4 million receivable relating to energy sales in California. As previously discussed in Significant Events, a provision of US$28.8 million to account for potential refund liabilities was recorded in December 2000. On March 17, 2004, the CAISO released its preliminary adjusted prices indicating that TransAlta’s refund liability is now US$46.0 million. Based on these preliminary refund estimates, in the first quarter of 2004 TransAlta increased its provision for potential refund liabilities by US$17.2 million (Cdn$22.9 million) to US$46.0 million. The final adjusted prices were released in October 2004 and were substantially the same as those released on March 17, 2004. TransAlta has prepared a petition for relief from the refund obligation that may be filed once FERC provides stakeholders with a direction on the filing of such positions. TransAlta’s fixed price trading positions were as follows:
| |
Electricity | Natural Gas | |||
Units (000s) | (MWh) | (GJ) | ||
Fixed price payor, notional amounts, Dec. 31, 2004 | 14,138.0 | 35,221.7 | ||
Fixed price payor, notional amounts, Dec. 31, 2003 | 13,872.6 | 45,638.6 | ||
Fixed price receiver, notional amounts, Dec. 31, 2004 | 15,854.2 | 29,721.2 | ||
Fixed price receiver, notional amounts, Dec. 31, 2003 | 13,061.8 | 67,738.3 | ||
Maximum term in months, Dec. 31, 2004 | 48 | 34 | ||
Maximum term in months, Dec. 31, 2003 | 33 | 24 | ||
Proprietary trading encompasses a range of contractual terms spanning from short-term speculative trading of one to 24 months to longer-term marketing transactions with potential terms greater than 24 months. Changes in trading positions from Dec. 31, 2003 to Dec. 31, 2004 are due to changing market conditions and corresponding regional strategy positioning.
Gross physical and financial settled sales of proprietary trading transactions are as follows:
Electricity (GWh) | ||||||
Year ended Dec. 31 | 2004 | 2003 | 2002 | |||
Physical | 61,165 | 55,506 | 61,089 | |||
Financial | 23,239 | 34,327 | 31,785 | |||
84,404 | 89,833 | 92,874 | ||||
Gas (million GJ) | ||||||
Year ended Dec. 31 | 2004 | 2003 | 2002 | |||
Physical | 122.4 | 100.1 | 101.5 | |||
Financial | 308.0 | 170.1 | 60.5 | |||
430.4 | 270.2 | 162.0 | ||||
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 3 9
In 2004, financial electricity volumes were lower than the same period in 2003 due to the elimination of trading in New York TCCs in 2003. Physical electricity volumes were higher in 2004 compared to the same period in 2003 due to the development of Eastern region real-time markets. Power trading strategies consist of shorter-term physical and financial trades in regions where TransAlta has assets and the markets that interconnect with those regions.
Electricity volumes in 2003 were lower than in 2002 due to the consolidation of the Annapolis trading office. The increase in gas volumes relates to the increased use of heat rate contracts, which involve a gas component, to manage power price risk. Gas trading, independent of power trading strategies, continues to be a small part of the risk taken in the marketplace. TransAlta’s trading activities are mainly short-term transactions, thereby limiting credit risk and maintaining low working capital requirements.
The corporation’s electrical transmission contracts net trading position of 4.4 million MWh at Dec. 31, 2004 is lower than the net trading position of 7.4 million MWh at Dec. 31, 2003, primarily due to the expiration of electrical transmission contracts owned.
In accordance with EITF 02-03, physical transmission is accounted for using accrual accounting. At Dec. 31, 2004, TransAlta recorded a prepaid asset of $1.5 million related to these transmission contracts compared to approximately $2.0 million at Dec. 31, 2003. The transmission contracts relate to the period from April 2004 to March 2005 and are amortized over this period. Physical transmission is widely used in the California market. The maximum term of these contracts is 12 months.
P R I C E R I S K M A N A G E M E N T
TransAlta’s price risk management assets and liabilities represent the value of unsettled (unrealized) proprietary trading transactions and those asset-backed trading transactions accounted for on a fair value basis. With the exception of transmission contracts, the fair value of all energy trading activities is based on quoted market prices. The fair value of financial transmission contracts is based upon statistical analysis of historical data. All transmission contracts are accounted for in accordance with EITF 02-03. The following tables show the balance sheet classifications for price risk management assets and liabilities as well as the changes in the fair value of the net price risk management assets for the period:
Year ended Dec. 31 | 2004 | 2003 | ||||
Balance Sheet | ||||||
Price risk management assets | ||||||
Current | $ | 61.4 | $ | 68.4 | ||
Long-term | 32.5 | 31.6 | ||||
Price risk management liabilities | ||||||
Current | (49.9) | (64.3) | ||||
Long-term | (28.5) | (29.9) | ||||
Net price risk management assets outstanding | $ | 15.5 | $ | 5.8 | ||
Fair value | ||||||
Change in fair value of net assets | ||||||
Net price risk management assets outstanding at Dec. 31, 2003 | $ | 5.8 | ||||
New contracts entered into during the period | 14.9 | |||||
Changes in values attributable to market price and other market changes | (5.6) | |||||
Contracts realized, amortized or settled during the period | (4.3) | |||||
Changes in values attributable to discontinued hedge treatment of certain contracts | 4.7 | |||||
Net price risk management assets outstanding at Dec. 31, 2004 | $ | 15.5 | ||||
The net price risk management assets and liabilities increased by $9.7 million compared to Dec. 31, 2003 primarily due to the realization of a $4.7 million price risk management asset resulting from the discontinuance of hedge accounting related to a long-term power contract. The remaining increase of $5.0 million relates to the net effect of new contracts executed in the period with associated fair value changes, offset by contracts settled or amortized in the period. Changes in net price risk management assets and liabilities are generally reflected within the gross margin of both Energy Marketing and Generation business segments.
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The source of the valuations of the above contracts and maturities over each of the next five calendar years
and thereafter is as follows: | ||||||||||||||||||
2009 and | ||||||||||||||||||
2005 | 2006 | 2007 | 2008 | thereafter | Total | |||||||||||||
Prices actively quoted | $ | 8.1 | $ | 1.8 | $ | 1.1 | $ | 1.0 | $ | – | $ | 12.0 | ||||||
Prices based on models | 3.5 | – | – | – | – | 3.5 | ||||||||||||
$ | 11.6 | $ | 1.8 | $ | 1.1 | $ | 1.0 | $ | – | $ | 15.5 | |||||||
TransAlta’s proprietary trading activities are mainly short-term transactions under 24 months in duration, thereby limiting credit risk and maintaining low working capital requirements. Transactions extending past 2005 are Generation asset-backed contracts that do not qualify for hedge accounting and have a low risk profile including long-term fixed for floating power swaps and a heat rate swap.
N E T I N T E R E S T E X P E N S E A N D F O R E I G N E X C H A N G E
Year ended Dec. 31 | 2004 | 2003 | 2002 | ||||||
Interest on recourse and non-recourse debt | $ | 207.9 | $ | 234.1 | $ | 172.9 | |||
Interest on preferred securities | 44.5 | 36.8 | 34.9 | ||||||
Interest income | (10.3) | (5.0) | (8.7) | ||||||
Interest allocated to discontinued operations | – | – | (2.4) | ||||||
Capitalized interest | (20.0) | (45.2) | (79.1) | ||||||
Net interest expense | $ | 222.1 | $ | 220.7 | $ | 117.6 | |||
In 2004, net interest expense increased by $1.4 million compared to the same period in 2003 due to decreased capitalized interest and recognition of $7.6 million of financing costs related to the $300 million preferred securities that are to be redeemed in February 2005, partially offset by decreased debt levels, decreased interest rates and increased interest income. Capitalized interest is lower as the result of the completion of the Sarnia, Campeche and Chihuahua plants, partially offset by the construction of the Summerview Wind Farm and Genesee 3. Interest income is higher due to favourable income tax assessments.
Net interest expense increased by $103.1 million in 2003 compared to 2002. The increase is primarily due to lower capitalized interest, higher debt levels, higher effective interest rates and approximately $5 million a month of interest expense related to the CE Gen non-recourse debt. The decrease in capitalized interest in 2003 compared to 2002 is a result of the commissioning of the Sarnia, Centralia Gas, Campeche and Chihuahua plants, partially offset by the Genesee 3 project.
The foreign exchange loss in the year ended Dec. 31, 2003 relates primarily to a reduction in the value of a commodity tax receivable in Mexico associated with equipment purchases and was the result of the weakening of the Mexican peso relative to the U.S. dollar. The receivable was collected in the second quarter of 2003.
I N C O M E TA X E S
Year ended Dec. 31 | 2004 | 2003 | 2002 | ||||||
Income tax expense | $ | 50.1 | $ | 64.6 | $ | 9.4 | |||
Effective tax rate (%) | 23.8 | 21.6 | 12.3 | ||||||
The 2004 expense is $14.5 million lower than the comparable period due to a decrease in pre-tax earnings, and a current income tax recovery of NZ$8.0 million (Cdn$6.8 million) received in the second quarter of 2004. The tax recovery resulted from a favourable settlement from the New Zealand Inland Revenue relating to the 1999 taxation year. The effective income tax rate for 2004 is consistent with the same period in 2003.
Income tax expense increased by $55.2 million in 2003 compared to 2002 due to increased earnings. The 2003 effective income tax rate, expressed as a percentage of earnings from continuing operations before income taxes and non-controlling interests, reflects the impact of the taxation on the sale of the Sheerness Generating Station, the recognition of the deferred gain and the impairment charges.
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 4 1
N O N - C O N T R O L L I N G I N T E R E S T S
2004 | 2003 | 2002 | |||||||
Year ended Dec. 31 | |||||||||
Non-controlling interests | $ | 46.0 | $ | 34.2 | $ | 20.1 | |||
The increase in earnings attributable to non-controlling interests in 2004 of $11.8 million compared to the same period in 2003 is a result of the sale of the Sheerness Generating Station to TA Cogen in the third quarter of 2003.
Earnings attributable to non-controlling interests in 2003 increased by $14.1 million compared to 2002 due to the sale of the Sheerness Generating Station to TA Cogen and the 25 per cent interest in CE Gen’s Saranac facility.
C O N S O L I D AT E D B A L A N C E S H E E T S
The following chart outlines significant changes in the consolidated balance sheets between Dec. 31, 2004
and Dec. 31, 2003: | |||
Increase/ | |||
(decrease) | Explanation | ||
Cash and cash equivalents | $ | (17.9) | Refer to Consolidated Statements of Cash Flows. |
Income taxes receivable | (48.8) | Funding for settlement with taxation authorities | |
on prior year audit issues and refunds of tax | |||
prepayments made in prior years. | |||
Long-term receivables | (120.1) | Receipt of the Zinc Recovery receivable at CE Gen, | |
increase in California receivable provision and | |||
transfer of remaining California receivable to | |||
current receivables. The Zinc Recovery funds were | |||
used to repay the CE Gen secured bonds. | |||
Property, plant and equipment, | (141.1) | Decrease due to depreciation and asset disposals | |
net of accumulated depreciation | partially offset by the construction of the | ||
Summerview Wind Farm and Genesee 3 project | |||
and capitalized maintenance. | |||
Intangible assets | (84.9) | Amortization of CE Gen sales contracts. | |
Future income tax assets | 33.8 | Increase in unused tax losses that are expected | |
(including current portion) | to be recovered in future years. | ||
Other assets (including current portion) | 43.7 | Increase in mark-to-market valuation of | |
cross-currency swaps. | |||
Short-term debt | (85.4) | Repayment of short-term debt. | |
Accounts payable and accrued liabilities | (68.9) | Decreased payables related to capital expenditures. | |
Long-term debt (including current portion) | (88.2) | Repayment of long-term debt. | |
Deferred credits and other long-term | 13.0 | Primarily due to an increase in mark-to-market | |
liabilities (including current portion) | valuation of cross-currency swaps. | ||
Non-controlling interests | 138.5 | Increase in non-controlling interest due to the | |
Sheerness and Meridian transactions. | |||
Shareholders’ equity | 22.2 | Issuance of common shares offset by a reduction | |
in retained earnings reflecting higher dividends | |||
than earnings. | |||
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L I Q U I D I T Y A N D C A P I TA L R E S O U R C E S
TransAlta raises substantially all external capital to be invested in the various business units and affiliated or subsidiary companies as required. This strategy allows TransAlta to gain access to sufficient capital at the lowest overall cost to finance growth opportunities and provide financial flexibility. Historically, external financing has been obtained from borrowings under credit facilities, proceeds from the disposal of non-core assets and the issuance of debt, preferred securities and equity. Internally, capital is also raised through operations. A summary of cash flows is as follows:
Year ended Dec. 31 | 2004 | 2003 | 2002 | ||||||
Cash and cash equivalents, beginning of year | $ | 155.0 | $ | 143.3 | $ | 62.0 | |||
Cash flow from (used in): | |||||||||
Operating activities | 613.4 | 526.9 | 398.6 | ||||||
Investing activities | (65.4) | (341.0) | (32.0) | ||||||
Financing activities | (558.8) | (165.5) | (286.0) | ||||||
Translation of foreign currency cash | (7.1) | (8.7) | 0.7 | ||||||
Cash and cash equivalents, end of year | $ | 137.1 | $ | 155.0 | $ | 143.3 | |||
In October 2003, the corporation renewed its $1.0 billion medium-term note shelf registration. The corporation also increased its committed bank credit facility to $1.5 billion from $1.2 billion in July 2003 in order to increase its liquidity. The corporation maintained approximately $340 million of uncommitted credit facilities.
In November 2003, TransAlta issued US$300.0 million of 10-year senior notes under a US$1.0 billion shelf registration statement filed May 14, 2002. The notes bear interest at 5.75 per cent per annum. Proceeds from the issuance were primarily used to refinance bonds that matured in 2003. In July 2004, the corporation renewed this US$1.0 billion shelf registration.
Operating Activities
Operating activities after changes in non-cash working capital provided cash of $613.4 million in 2004 compared to $526.9 million in 2003 and $398.6 million in 2002. The increase in 2004 is due to an improved working capital position and increased cash earnings. The increase in 2003 is primarily due to higher earnings and the collection of commodity tax receivables in the U.S. and Mexico (US$79.0 million) in 2003, the settlement of a disputed ancillary services revenue issue with the Balancing Pool of Alberta ($49.9 million) in 2002, the timing of cash tax obligations ($55.6 million) in the third quarter of 2002 and the final installment of 2001 income taxes paid in the first quarter of 2002 ($109.0 million).
Investing Activities
Investing activities used cash of $65.4 million in 2004 compared to $341.0 million in 2003 and $32.0 million in 2002.
In 2004, additions to capital assets totalled $365.8 million and consisted primarily of completion of the Summer-view Wind Farm, continuing construction of the Genesee 3 project and capitalized planned maintenance.
In 2003, additions to capital assets totalled $555.7 million and consisted primarily of the completion of the two Mexican plants and the McBride Lake Wind Farm and the continuing construction of the Genesee 3 project. Acquisitions consisted of the purchase of a 50 per cent interest in CE Gen for $323.4 million (net of cash acquired of $43.2 million).
Cash provided by disposals and the sale of capital assets in 2004 was $159.7 million, comprised primarily of $116.5 million of proceeds from the sale of TransAlta Power partnership units and $24.2 million received on the sale of the Meridian Cogeneration Facility and $11.7 million from the sale of a turbine.
Cash provided by disposals and the sale of capital assets in 2003 was $285.5 million, comprised of $149.9 million received from the sale of the Sheerness Generating Station, $65.8 million of proceeds from the sale of the head office building, $37.2 million of proceeds from the sale of TransAlta Power partnership units, $21.6 million of proceeds from the sale of the Goldfields pipeline and $11.0 million of proceeds from the sale of the Seebe land.
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 4 5
Financing Activities
Financing activities used cash of $558.8 million compared to $165.5 million in 2003 and $286.0 million in 2002.
In 2004, payments included net long-term debt repayment ($289.5 million), net repayment of short-term debt ($85.4 million), cash dividends on common shares ($135.4 million) and non-controlling interest distributions ($48.4 million), some of which were funded from cash flow from operating activities.
In 2003, net proceeds on the issuance of common shares ($265.0 million) were more than offset by net long-term debt repayment ($56.5 million), net repayment of short-term debt ($170.2 million), cash dividends on common shares ($158.3 million) and non-controlling interest distributions ($38.9 million), some of which were funded from cash flow from operating activities.
In 2002, the issuance of US$300.0 million in senior notes was more than offset by the repayment of short-term debt ($247.1 million), repayment of long-term debt ($454.5 million), cash dividends ($115.5 million) and the net redemption of common shares ($48.1 million).
In 2003, TransAlta repaid the following senior secured debt of TAU:
Maturity | Rate | Amount | |||||
Debentures | 2003 | 7.25% | $ | 150.0 | |||
Debentures | 2003 | 8.35% | $ | 200.0 | |||
In 2004, under the terms of the Normal Course Issuer Bid, the corporation purchased 143,500 common shares for cancellation (2003 – nil; 2002 – 2.0 million).
TransAlta’s dividends per common share were $1.00 in 2004, 2003 and 2002.
Financing Arrangements
TransAlta raises capital in the Canadian and U.S. markets. TransAlta has the following financing arrangements in place:
- US$1.0 billion shelf registration program; no amount has been issued since its renewal in July 2004;
- $1.0 billion medium-term note program; no amount has been issued since its renewal in October 2003. This program remains valid until November 2005, and is expected to be renewed;
- $34.4 million of commercial paper issued at Dec. 31, 2004;
- $1.5 billion committed syndicated bank credit facility, with $200.0 million utilized at Dec. 31, 2004. $600.0 million of the facility was renewed in July 2004 and expires in June 2005 and the remainder expires in June 2007. The facility is expected to be renewed; and
- $333.2 million of additional bank credit facilities, with $246.8 million utilized at Dec. 31, 2004. All of these facilities are non-committed.
At Dec. 31, 2004, the corporation had approximately $1.35 billion of credit available from its committed and uncommitted credit facilities.
In addition to the above, the corporation has US$127.9 million of project financing for the Campeche project, which became non-recourse in the first quarter of 2004. It is the corporation’s expectation that future financing requirements, including financing requirements in foreign jurisdictions, will be met primarily through raising capital at the TransAlta Corporation level.
At Dec. 31, 2004, TransAlta had a working capital ratio of 0.78 compared to 0.98 at Dec. 31, 2003. This decrease is attributable to an increase in the current portion of long-term debt of $300 million, representing the portion of the preferred securities which will be redeemed in February 2005. TransAlta expects to have sufficient sources of internal and external capital to finance operations and growth in the short and long term.
In 2005, cash will be provided by a combination of cash flow from operations and utilization of various credit facilities. Cash requirements include planned maintenance, additions to capital assets, dividend payments and repayment of short-term and maturing senior debt. Cash provided by operations in 2004 was $613.4 million and at Dec. 31, 2004, there were approximately $1.35 billion of funds available under credit facilities. In 2005, capital expenditures are expected to be $360 million to $375 million and $587.7 million of existing debt is scheduled to be repaid in 2005.
Long-term funding is provided through the maintenance of investment grade credit ratings and a carefully managed capital structure, which together create a strong balance sheet and ready access to capital markets at competitive rates. The corporation’s objective is to manage the maturities of the various securities on issue
4 6 Tr a n s A l t a C o r p o r a t i o n A R / 0 4
such that no more than 15 per cent of the total outstanding securities mature in any one year. The corporation’s target is to maintain a capital structure and coverage ratios consistent with investment grade credit ratings. The corporation’s capital structure consisted of the following components at Dec. 31, 2004, 2003 and 2002:
2004 | 2003 | 2002 | |||||||||||||
Debt, net of cash and interest-earning investments | $ | 2,655.2 | 42% | $ | 3,110.9 | 48% | $ | 2,830.0 | 50% | ||||||
Preferred securities | 475.0 | 8% | 475.0 | 7% | 475.0 | 8% | |||||||||
Other non-controlling interests | 616.4 | 10% | 477.9 | 7% | 263.0 | 5% | |||||||||
Common shareholders’ equity | 2,472.7 | 40% | 2,450.5 | 38% | 2,092.1 | 37% | |||||||||
$ | 6,219.3 | 100% | $ | 6,514.3 | 100% | $ | 5,660.1 | 100% | |||||||
At Dec. 31, 2004, TransAlta’s total debt (including non-recourse debt) to invested capital ratio was 47.4 per cent (42.0 per cent excluding non-recourse debt) compared to the Dec. 31, 2003 ratio of 47.7 per cent and the Dec. 31, 2002 ratio of 50.4 per cent.
Additional key financial ratios were as follows:
18.5%17.2%
1 | Cash flow from operations before changes in working capital plus net interest expense divided by interest on recourse and non-recourse debt less interest income. |
2 | Cash flow from operations before changes in working capital divided by two-year average of total debt. |
Contractual repayments of long-term debt, commitments under operating leases, fixed price purchase contracts and commitments under mining agreements are as follows:
2010 and | ||||||||||||||||||||||
2005 | 2006 | 2007 | 2008 | 2009 | thereafter | Total | ||||||||||||||||
Long-term debt1 | $ | 587.7 | $ | 409.2 | $ | 61.1 | $ | 169.6 | $ | 252.1 | $ | 1,753.2 | $ | 3,232.9 | ||||||||
Operating leases | 14.8 | 13.2 | 11.6 | 10.6 | 10.2 | 100.0 | $ | 160.4 | ||||||||||||||
Fixed price purchase contracts | 51.4 | 53.1 | 54.8 | 56.8 | 32.4 | 87.0 | $ | 335.5 | ||||||||||||||
Mining agreements | 81.9 | 36.7 | 36.8 | 33.3 | 18.6 | 300.3 | $ | 507.6 | ||||||||||||||
Total contractual cash obligations | $ | 735.8 | $ | 512.2 | $ | 164.3 | $ | 270.3 | $ | 313.3 | $ | 2,240.5 | $ | 4,236.4 | ||||||||
1 Includes capital lease obligations. |
In addition, the corporation has entered into a number of long-term power sales, gas purchase and transportation agreements in the normal course of operations as hedges of its operations.
In the normal course of operations, TransAlta and certain of its subsidiaries enter into agreements to provide financial or performance assurances to third parties. This includes guarantees, letters of credit and surety bonds that are entered into to support or enhance creditworthiness in order to facilitate the extension of sufficient credit for Energy Marketing trading activities, treasury hedging, Generation construction projects, equipment purchases and mine reclamation obligations.
At Dec. 31, 2004, the corporation had letters of credit outstanding of $187.6 million, US$197.7 million and 171.9 million Mexican pesos. The letters of credit were issued to counterparties that have credit exposure to certain subsidiaries. If a subsidiary does not pay amounts due under the covered contract, the counterparty may present its claim for payment to the financial institution, which in turn will request payment from the corporation. Any amounts owed by the corporation’s subsidiaries are reflected in the consolidated balance sheet. All letters of credit expire in 2005 and 2006.
The corporation had a surety bond in the amount of US$181.6 million in support of future asset retirement obligations at the Centralia mine outstanding at Dec. 31, 2004. The surety bond expires in October 2005. A provision for retirement obligations is included in deferred credits and other long-term liabilities(Note 12 to the consolidated financial statements).
TransAlta has provided guarantees of subsidiaries’ obligations under contracts that facilitate physical and financial transactions in various derivatives. To the extent liabilities related to these guaranteed contracts exist for trading activities, they are included in the consolidated balance sheet. To the extent liabilities exist related to these guaranteed contracts for hedges, they are not recognized on the consolidated balance sheet. The guarantees provided for under all contracts facilitating physical and financial transactions in various derivatives
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 4 7
at Dec. 31, 2004 was a maximum of $1.6 billion. In addition, the corporation has a number of unlimited guarantees. The fair value of the trading and hedging positions under contracts where TransAlta has a net liability at Dec. 31, 2004, under the limited and unlimited guarantees, was $345.2 million as compared to $381.3 million at Dec. 31, 2003.
TransAlta has also provided guarantees of subsidiaries’ obligations to perform and make payments under various other contracts. The amount guaranteed under these contracts at Dec. 31, 2004 was a maximum of $662.5 million, as compared to $828.6 million at Dec. 31, 2003. To the extent actual obligations exist under the performance guarantees at Dec. 31, 2004, they are included in accounts payable and accrued liabilities.
The corporation has approximately $1.35 billion of undrawn collateral available to secure these exposures.
During construction and until certain conditions were met, the corporation provided a guarantee to the lenders of the Campeche plant. On April 5, 2004, the guarantee was released and the US$133.6 million of debt related to the plant became non-recourse to the corporation.
At Dec. 31, 2004, the credit ratings for the corporation’s various securities as determined by Standard & Poor’s (S&P), the Dominion Bond Rating Service (DBRS) and Moody’s Rating Services were as follows:
Credit Ratings | S&P | DBRS | Moody’s |
TransAlta Corporation | |||
Issuer rating | BBB- | Baa 2 | |
Commercial paper | R-2 (high) | ||
Secured commercial paper | R-1 (low) | ||
Senior unsecured debentures | BBB- | BBB | Baa 2 |
Preferred securities/stock | BB | Pfd-3y | |
TransAlta Utilities Corporation | |||
Issuer rating | BBB- | ||
Secured debt | BBB | A (low) | |
In January 2005, DBRS confirmed TransAlta's credit ratings of R-2 (high), BBB and Pfd-3y to the corporation’s commercial paper, senior unsecured debentures and preferred securities, respectively, all with a negative trend. In May 2004, DBRS assigned a rating of R-1 (low) to TransAlta’s secured commercial paper program. In July 2004, Moody’s confirmed TransAlta’s credit rating of Baa 2 with a negative outlook. In December 2004, S&P affirmed TransAlta's credit rating of BBB- (stable) and BB to the corporation’s unsecured debentures and preferred securities.
On Feb. 17, 2005, TransAlta had approximately 195.1 million common shares outstanding, plus outstanding employee stock options to purchase an additional 2.9 million shares.
O F F - B A L A N C E S H E E T A R R A N G E M E N T S
Disclosure is required of all off-balance sheet arrangements such as transactions, agreements or contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities or variable interest entities that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources. The corporation has no such off-balance sheet arrangements.
Under Canadian GAAP, most derivatives used in hedging relationships are not recorded on the balance sheet(Note 1(O))to the consolidated financial statements. Gains or losses during the term of the hedge are deferred and recognized in earnings in the same period and financial statement caption as the hedged exposure (settlement accounting). The fair values of these derivatives are disclosed inNote 19to the consolidated financial statements. The corporation also enters into long-term electricity purchase and sale, gas purchase and transportation agreements in the normal course of operations. These contracts are not recorded on the balance sheet under Canadian GAAP. Under U.S. GAAP, some of these contracts meet the definition of a derivative, and would require mark-to-market accounting, but are eligible for the normal purchase and sale exemption under FASB Statement 133. This exemption is available as electricity cannot be stored in significant quantities and due to the requirement for electricity generators to maintain sufficient capacity to meet customers’ demands, and is also available for physically settled commodity contracts if certain criteria are met.
Information regarding guarantees has been disclosed in the Liquidity and Capital Resources section.
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R E L AT E D PA RT Y T R A N S A C T I O N S
As previously discussed in Significant Events, on Dec. 1, 2004, TransAlta completed the sale of its 50 per cent interest in the 220-MW Meridian Cogeneration Facility located in Lloydminster, Saskatchewan to TA Cogen for fair value of $110.0 million. TA Cogen (owned 50.01 per cent by TransAlta and 49.99 per cent by TA Power) financed the acquisition through the use of $50.0 million of cash on hand and by the issuance of $30.0 million of units to each of TransAlta Power and TEC. TA Cogen also issued an advance to TEC for $30.0 million. TransAlta recorded a gain of $11.5 million after-tax or $0.06 per common share.
On July 31, 2003, TransAlta completed the sale of its 50 per cent interest in the two-unit, 756-MW coal-fired Sheerness Generating Station to TA Cogen for $630.0 million. The exchange amount was at fair value and was determined based on an estimate of the future net cash flows of the plant and approved by the independent directors of TA Cogen. There are no ongoing contractual commitments or arrangements resulting from this sale apart from the provision of operational and management services under normal commercial terms for the Sheerness plant.
The obligation to purchase all of TransAlta Power’s interest in TA Cogen on Dec. 31, 2018 (resulting from the 1998 sale of an interest in three Ontario cogeneration plants held by TA Cogen to TransAlta Power) was removed as part of the Sheerness transaction. Accordingly, the unamortized portion of the 1998 deferred gain was recognized in 2003. In addition, the management agreements between TransAlta, TransAlta Power and TA Cogen were amended to remove the mechanism for the deferral of management fees and remove the obligation for TransAlta Power and TA Cogen to pay management fees to TransAlta in the future. As consideration for the amendments, TransAlta received $1.0 million from TransAlta Power and $5.0 million from TA Cogen.
In February 2003, TransAlta entered into an agreement with CE Gen whereby TransAlta buys available power from certain CE Gen subsidiaries under normal commercial terms. In addition, CE Gen has entered into contracts with related parties to provide administrative and maintenance services.
For the period November 2002 to November 2007, TA Cogen entered into a transportation swap transaction with a wholly-owned subsidiary of TransAlta, TEC. The business purpose of the transportation swap was to provide TA Cogen with the delivery of fixed price gas without being exposed to escalating costs of pipeline transportation for two of its plants over the period of the swap. This stabilizes cash distributions in TA Cogen and thereby preserves the value of the limited partnership as a financing vehicle of TransAlta. The notional gas volume in the transaction was the total delivered fuel for both facilities. Exchange amounts are based on the market value of the contract. TransAlta entered into an offsetting contract with an external third party; therefore TransAlta has no risk other than counterparty risk.
TA Cogen entered into a fixed-for-floating gas swap transaction with TEC for a 61-month period starting Dec. 1, 2000. The swap transaction provides TA Cogen with fixed price gas for both the Mississauga and Ottawa plants over the period. The floating prices associated with the Mississauga and Ottawa cogen plants’ long-term fuel supply agreements were transferred to TransAlta Energy’s account. The notional gas volume in the transaction was the total delivered fuel for both facilities. As consideration and in negotiation, TA Cogen transferred the right to incremental revenues associated with curtailed electrical production and subsequent higher revenue gas sales. At Dec. 31, 2004, the portion of the contract related to the non-controlling interest had a fair value liability of $4.9 million (2003 – $7.9 million).
E M P L O Y E E S H A R E O W N E R S H I P
TransAlta employs a variety of stock-based compensation plans to align employee and corporate objectives. At Dec. 31, 2004, 2.9 million options to purchase the corporation’s common shares were outstanding, with 2.0 million exercisable at the reporting date. At Dec. 31, 2003, 3.1 million options to purchase the corporation’s common shares were outstanding, with 1.5 million exercisable at the reporting date.
Under the terms of the Performance Share Ownership Plan (PSOP), certain employees receive awards which, after three years, make them eligible to receive a set number of common shares or cash equivalent plus dividends thereon based upon the performance of the corporation relative to a selected group of publicly traded companies. After three years, once PSOP eligibility has been determined, 50 per cent of the common shares may be released to the participant, while the remaining 50 per cent will be held in trust for one additional year. At Dec. 31, 2004, there were 1.5 million PSOP awards outstanding.
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 4 9
Under the terms of the Employee Share Purchase Plan, the corporation will extend an interest-free loan to employees below executive level of up to 30 per cent of the employee’s base salary for the purchase of common shares of the corporation from the open market. The loan is repaid over a three-year period by the employee through payroll deductions unless the shares are sold, at which point the loan becomes due on demand. At Dec. 31, 2004, 0.4 million shares had been purchased by employees under this program.
E M P L O Y E E F U T U R E B E N E F I T S
TransAlta has registered pension plans in Canada and the U.S. covering substantially all employees of the corporation, its domestic subsidiaries and specific named employees working internationally. These plans have defined benefit and defined contribution options and, in Canada, there is a supplemental defined benefit plan for certain employees. The defined benefit option of the registered pension plan ceased for new employees on June 30, 1998. The latest actuarial valuations of the registered and supplemental pension plans were as at Dec. 31, 2004.
The corporation provides other health and dental benefits to the age of 65 for both disabled members (other post-employment benefits) and retired members (other post-retirement benefits). The latest actuarial valuation of these other plans was as at April 30, 2002.
The supplemental pension plan is an obligation of the corporation. The corporation is not obligated to fund the supplemental plan but is obligated to pay benefits under the terms of the plan as they come due. The corporation has posted a letter of credit in the amount of $38.5 million to secure the obligations under the supplemental plan.
R I S K FA C T O R S A N D R I S K M A N A G E M E N T
TransAlta uses a multi-level risk management oversight structure to manage the corporation’s various risk and energy trading exposures.
The Audit and Environment (A&E) Committee provides assistance to the Board of Directors in fulfilling its oversight responsibility relating to the integrity of the corporation’s financial statements and the financial reporting process; the systems of internal accounting and financial controls; the internal audit function; the external auditors’ qualifications, independence, performance and reports; and the legal and environmental compliance programs as established by management and the Board of Directors.
The Exposure Management (EM) Committee is chaired by the Chief Financial Officer and is comprised of the Directors of Financial Operations for each business unit, the Executive Vice-President of Commercial Development and Marketing, Vice-President and Treasurer, Vice-President and Comptroller and the Director of Risk Management. The EM Committee is responsible for the review, monitoring and reporting on compliance of these financial and commodity risk exposure management policies.
The following addresses some, but not all, risk factors that could affect TransAlta’s future results. A discussion of critical estimates made in the application of accounting policies is provided in the Critical Accounting Policies and Estimates section that follows.
Commodity Price Risk
The corporation has exposure to movements in certain commodity prices, including the market price of electricity and fuels used to produce electricity in both its electricity generation and proprietary trading businesses.
The corporation’s Alberta coal-fired and hydroelectric facilities operate under the Alberta government mandated PPAs which, among other things, establish the price at which power will be supplied. In addition to the Alberta PPAs, the corporation has entered into a variety of short- and long-term contracts to minimize its exposure to short-term fluctuations in electricity prices. In 2004, TransAlta had approximately 71 per cent of production under long-term contracts (2003 – 74 per cent) and 84 per cent (2003 – 91 per cent) of production was contracted for terms greater than one year. In the event of a planned or unplanned plant outage or other similar event, however, the corporation is exposed to changes in electricity prices on purchases of electricity from the market to fulfill its supply obligations under these short- and long-term contracts. The corporation actively seeks to mitigate this exposure through continued and proper maintenance of its electricity generating plants, force majeure clauses negotiated in its contracts, trading activities and insurance.
The corporation buys natural gas and some of its coal to supply the fuel needed to operate its facilities. The corporation has exposure to increases in the cost of such fuels to the extent such increases are greater than the increases in the price that the corporation can obtain for the electricity it produces. A significant portion
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of the coal used in electricity generation is from coal reserves owned by TransAlta, thereby limiting the corporation’s exposure to fluctuations in the market price of coal. In 2004, 81 per cent (2003 – 71 per cent) of TransAlta’s cost of gas used in generating electricity was contractually fixed or passed through to customers and 100 per cent (2003 – 100 per cent) of the corporation’s purchased coal costs were contractually fixed.
The corporation’s fuel supply and fuel costs for gas-fired plants are managed with short-, medium- and long-term gas supply contracts, hedging transactions and contractual agreements that provide for the flow-through of gas costs. The corporation believes adequate supplies of natural gas at reasonable prices will be available for plants when existing supply contracts expire.
Production and gross margins from the merchant gas plants are subject to changes in spark spreads. TransAlta has not entered into fixed commodity agreements for gas for these merchant plants as gas will be purchased concurrent with spot market spark spreads being adequate to produce and sell electricity.
The corporation’s proprietary trading of gas and electricity is limited, strictly controlled and managed through the use of VAR methodologies.
VAR is the primary measure used to manage Energy Marketing’s exposure to market risk resulting from trading activities. VAR is monitored on a daily basis, and is used to determine the potential change in the value of the corporation’s marketing portfolio over a three-day period within a 95 per cent confidence level resulting from normal market fluctuations. Stress tests are performed weekly on both earnings and VAR to measure the potential effects of various market events that could impact financial results, including fluctuations in market prices, volatilities of those prices and the relationships between those prices.
The corporation estimates VAR using the historical variance/covariance approach. Currently, there is no uniform energy industry methodology for estimating VAR. An inherent limitation of historical variance/covariance VAR is that historical information used in the estimate may not be indicative of future market risk.
Another method of looking at VAR is based on a 95 per cent confidence interval over a 3-day holding period. For comparison purposes, the following table provides this average daily VAR of the corporation’s marketing portfolio for 2004 and 2003:
3-day average VAR – 95% confidence level | 2004 | 2003 |
$ 3.8 | $ 3.6 |
Currency Rate Exposure
The corporation has exposure to various currencies as a result of its investments and operations in foreign jurisdictions, the earnings from those operations and the acquisition of equipment and services from foreign suppliers. The corporation has exposures primarily to the U.S., Mexican and Australian currencies. These exposures are managed through the use of a variety of hedging instruments including direct-debt, cross-currency interest rate swaps and foreign currency forward sales contracts. At Dec. 31, 2004, the corporation had hedged approximately 98.7 per cent (2003 – 100 per cent) of its foreign currency rate exposure to its investment in foreign operations on a pre-tax basis. TransAlta’s strategy is to offset 90-100 per cent of all foreign currency exposures.
Translation gains and losses related to the carrying value of the corporation’s foreign operations are deferred and included in the cumulative translation account in shareholders’ equity. At Dec. 31, 2004, the balance in this account was a $49.5 million loss compared to a $39.1 million loss at the end of 2003.
Credit Risk
If the counterparties to the corporation’s contracts are unable to meet their obligations, the corporation’s revenues could be adversely affected. TransAlta actively manages its exposure to credit risk by assessing the ability of counterparties to fulfill their obligations under the related contracts prior to entering into such contracts. The corporation sets strict credit limits for each counterparty and the mix of counterparties based on their credit ratings. Counterparty exposures for trading activities are monitored daily. If the limits are exceeded, the corporation takes steps to reduce additional credit exposure by requesting collateral if applicable, or by halting trading activity. However, there can be no assurances that the corporation will be successful in identifying creditworthy counterparties or monitoring trading activities.
TransAlta is exposed to minimal credit risk for Alberta PPAs because under the terms of these arrangements all receivables are secured by letters of credit.
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A summary of the corporation’s credit risk exposure for its trading operations at Dec. 31, 2004, including asset-backed trading is provided below:
Net | ||||||||||||||
Exposure | Number of | exposure of | ||||||||||||
before | counterparties | c | ounterparties | |||||||||||
credit | Credit | Net | greater | greater | ||||||||||
Rating | collateral | collateral | exposure | than 10% | than 10% | |||||||||
Investment grade | $ | 87.0 | $ | 6.1 | $ | 80.9 | 1 | $ | 15.3 | |||||
Non-investment grade | 3.3 | 1.8 | 1.5 | – | – | |||||||||
No external rating, internally rated – | ||||||||||||||
investment grade | 17.2 | – | 17.2 | – | – | |||||||||
No external rating, internally rated – | ||||||||||||||
non-investment grade | 4.4 | 4.0 | 0.4 | – | – | |||||||||
$ | 111.9 | $ | 11.9 | $ | 100 | 1 | $ | 15.3 | ||||||
The maximum credit exposure to any one customer, excluding the California Independent System Operator and California Power Exchange Corp. discussed earlier in the Energy Marketing Segmented discussion, and including the fair value of open trading positions, is $15.3 million receivable.
Liquidity Risk
TransAlta is exposed to liquidity risk under certain electricity and natural gas purchase and sales contracts entered into for the purposes of asset-backed sales or proprietary trading. Liquidity risk relates to TransAlta’s commitments to meet margin and collateral requirements under these contracts. The terms and conditions of these contracts may require TransAlta to provide collateral when the fair value of these contracts is both negative (out-of-the-money) and in excess of any credit limits granted by TransAlta’s counterparties. The fair value of these contracts changes due to changes in commodity prices and foreign exchange rates. These contracts are out-of-the-money in these circumstances: (i) for purchase agreements, when forward commodity prices are less than contracted prices; and (ii) for sales agreements, when forward commodity prices exceed contracted prices. Downgrades in TransAlta’s creditworthiness may decrease the credit limits granted by TransAlta’s counterparties.
In the absence of any credit limits granted by TransAlta’s counterparties, TransAlta’s maximum collateral requirements would have been $528.2 million at Dec. 31, 2004. Collateral available was approximately $1.35 billion.
Interest Rate Exposure
The corporation has exposure to movements in interest rates and manages this exposure by maintaining a limit on the amount of debt subject to floating interest rates. At Dec. 31, 2004, approximately 25 per cent (2003 – 24 per cent) of the corporation’s total debt portfolio was subject to movements in floating interest rates through a combination of floating rate debt and interest rate swaps.
Hydro Risk
TransAlta’s Hydro operations financial performance is partially dependent upon the availability of water in a given year. The availability of water is difficult to forecast as it is driven by non-controllable factors, primarily weather, which impact the volume, timing and location of precipitation throughout the province of Alberta. Such water availability introduces a degree of volatility in revenues earned by TransAlta’s Hydro operations from year to year. This risk is complicated by obligations imposed within the PPA applicable to the corporation’s hydro plants. A monthly financial obligation must be paid to the PPA Buyer, based on a predetermined quantity of energy and ancillary services at market prices, regardless of TransAlta’s ability to generate such quantities. TransAlta manages these risks on a real-time basis by monitoring water resources throughout Alberta to the best of its ability, and optimizing this resource against real-time electricity market opportunities. TransAlta also plays an important role in the management of water flows and levels in several key areas of Alberta, including two major cities. TransAlta carefully balances all of these factors together to achieve optimal productivity with the water resources available.
Operational Risk
The corporation’s plants are exposed to operational risks such as fatigue cracks in boilers, corrosion in boiler tubing, turbine failures and other issues that can lead to outages. A comprehensive plant maintenance program and regular turnarounds reduce this exposure. If the plants do not meet the availability or production targets specified in the PPAs or other long-term contracts, then the corporation must either compensate the purchaser for the loss in the availability of production or suffer a reduction in electrical or capacity payments. Consequently,
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an extended outage could have a material adverse effect on the business, financial condition, results of operations or cash flows of the corporation. Insurance and force majeure clauses in the PPAs and other long-term contracts further mitigate this exposure.
The construction and development of generating facilities and acquisition activities are subject to various environmental, engineering and construction risks relating to cost-overruns, delays and performance. The corporation attempts to minimize these risks by performing detailed analysis of project economics prior to construction or acquisition and by securing favourable power sales agreements.
Of the corporation’s labour, 58 per cent is covered under 12 collective bargaining agreements. Nine agreements were renegotiated in 2004 with seven of those being renewed within 2004 and with two anticipated for renewal in early 2005. The remaining three agreements will be renewed in 2005. Management does not anticipate any significant issues in the renegotiation of these agreements.
Environmental, Health and Safety Risk
The corporation’s operations are subject to extensive federal, provincial, state and local environmental regulation. If the corporation does not comply with environmental requirements, regulatory agencies could seek to impose civil, administrative or criminal liabilities on the corporation, as well as seek to curtail its operations. TransAlta’s approach is to continually improve the management of operational risks in the areas of environment, health and safety while developing mechanisms to manage future risks. These programs are integrated into the operations and management systems of the corporation and are designed to mitigate the potential competitive risks to its fossil-fuelled generation plants from future changes in environmental policy.
TransAlta has implemented an ISO-based environmental, health and safety (EHS) management system, designed to continuously improve environmental and safety performance. At Dec. 31, 2004, 95 per cent of TransAlta’s plants had implemented the system. Compliance with both regulatory requirements and management system standards is regularly audited through TransAlta’s Performance Assurance policy and results are reported quarterly to the Board of Directors.
TransAlta is subject to federal, provincial and local environmental laws, regulations and guidelines concerning the generation and transmission of electrical and thermal energy and surface mining. TransAlta strives to maintain compliance with all environmental regulations relating to its operations and facilities. Quarterly reports on all EHS regulatory changes are provided to each facility to ensure compliance is maintained. TransAlta works with regulators in Canada and the U.S. to ensure regulatory changes are well-designed and cost-effective. If regulations were to change, however, the operational and financial impact on all plants would need to be assessed. Outcomes may include, but are not limited to: increased compliance, maintenance or capital costs; plant impairment charges; or the decommissioning of certain facilities.
TransAlta’s environmental policy requires that the environmental impacts and risks of the corporation’s activities are identified, assessed and managed. This is done by the use of an environmental management system to set environmental objectives and regularly review subsequent performance with senior management and mitigative action on longer-term environmental policy impacts such as climate change.
Emission reduction objectives for the power sector are being established by governments in Canada and the U.S. TransAlta has compliance plans over the next decade for greenhouse gases, mercury, sulphur dioxide and oxides of nitrogen, which will be adjusted as regulations are finalized. Where capital investment for control equipment may be required, TransAlta has technology review processes underway.
The Dow Jones Sustainability Index has again recognized TransAlta as one of the world’s best utility companies in terms of sustainability performance, and TransAlta is also recognized on the Financial Times Stock Exchange Good Global Index, a London-based sustainability index.
Regulatory and Political Risk
Certain of the markets in which the corporation operates are subject to significant regulatory oversight and control. The corporation is not able to predict whether there will be any changes in the regulatory environment or the ultimate effect of changes in the regulatory environment on its business. TransAlta manages these risks by working with governments, regulators and other stakeholders to attempt to resolve issues. In Ontario, new legislation was passed in December 2004 outlining a new electricity market structure. Over the course of 2005, the details of this new market will be more clearly defined and governing bodies and regulations will
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 5 3
be developed and implemented. The new market design provides for a mix of: i) regulated assets, ii) unregulated assets, and iii) government backed long-term contracts. The corporation’s Limited Partnership assets will retain their existing government contracts in the restructured market. The corporation remains in contact with regulators and legislators over the status of our Sarnia generating facility, but at this time the impact of the proposed changes is uncertain. In Alberta, a wholesale market review task force and a retail market review were initiated in 2004 to evaluate the functioning of the electricity market and consider market design changes. A market design policy recommendation is expected in 2005. TransAlta continues to work with the task force to ensure any regulatory changes are well-designed and cost-effective. If regulations were to change however, the operational and financial impact on all Alberta plants and trading operations would need to be assessed. Outcomes may include, but are not limited to: increased compliance, operating or capital costs; reduced operational flexibility; or reduced power prices and volatility.
International investments are subject to unique risks and uncertainties relating to the political, social and economic structures of the respective country and such country’s regulatory regime. The corporation attempts to mitigate this risk through the use of non-recourse financing and political risk insurance.
Transmission Risks
In August 2003, a blackout cut off electricity to millions of residents in the Northeastern U.S. and Eastern Canada. This type of event, although extremely unusual, is an ongoing risk for electric companies. This risk is mitigated through force majeure clauses in the Alberta PPAs and power sales contracts and access to multiple transmission lines.
Corporate Structure
The corporation conducts a significant amount of business through subsidiaries and partnerships. The corporation’s ability to meet and service debt obligations is dependent upon the results of operations of its subsidiaries and the payment of funds by such subsidiaries to the corporation in the form of distributions, loans, dividends or otherwise. In addition, TransAlta’s subsidiaries may be subject to statutory or contractual restrictions that limit their ability to distribute cash to the ultimate shareholder, the corporation.
General Economic Conditions
Changes in general economic conditions impact product demand, revenue, operating costs, timing and extent of capital expenditures, the net recoverable value of PP&E, results of financing efforts, credit risk and counterparty risk.
Income Taxes
The corporation’s operations are complex, and the computation of the provision for income taxes involves tax interpretations, regulations and legislation that are continually changing. The corporation’s tax filings are subject to audit by taxation authorities. Management believes that it has adequately provided for income taxes based on all information currently available.
Legal Contingencies
The corporation is occasionally named as a defendant in various claims and legal actions. Exposure to these claims is mitigated through levels of insurance coverage considered appropriate by management and active management of these claims. Except as disclosed inNote 23to the consolidated financial statements, the corporation does not expect the outcome of the claims or potential claims to have a materially adverse effect on the corporation as a whole.
Other Contingencies
The corporation maintains a level of insurance coverage deemed appropriate by management. There were no significant changes to TransAlta’s insurance coverage during 2004. The corporation’s insurance coverage may not be available in the future on commercially reasonable terms. There can be no assurance that insurance proceeds received by the corporation for any loss or damage will be sufficient.
Sensitivity Analysis
The following table shows the effect on net earnings and cash flows of changes in certain key variables. The analysis is based on business conditions and production volumes in 2004. Each separate item in the sensitivity assumes the others are held constant. While these sensitivities are applicable to the period and magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances, or for a greater magnitude of changes.
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Approximate impact | ||||||||||
Earnings | ||||||||||
Factor | Change | Cash flow | (after-tax) | |||||||
Electricity price | $ | 1.00/MWh increase | $ | 10.4 | $ | 10.4 | ||||
Natural gas price | $ | 0.1/GJ increase | (1.0) | (1.0) | ||||||
Availability/production | 1% increase | 14.1 | 14.1 | |||||||
Exchange rate (US$ per Cdn$) | US$0.01 decrease | - | (0.1) | |||||||
Interest rate | 1% increase | (8.2) | (5.5) | |||||||
Tax rate | 1% increase | (2.0) | (2.0) | |||||||
The impact of a $1.00 per MWh change in electricity prices has minimal impact on cash flow and after-tax earnings, as approximately 84 per cent of output is at contractually fixed prices. A change in natural gas prices also has minimal impact as 81 per cent of gas costs have been contractually fixed or flow through to customers under terms of agreements.
The calculation of the impact of a one per cent change in availability assumes that production levels will change by an equivalent amount at the contracted plants. An increase in availability at the merchant gas plants would not result in increased production.
TransAlta’s hedging strategies have minimized the impact of changes in exchange rates and interest rates as the corporation’s net investments in foreign operations have been hedged and interest rates on approximately 75 per cent of TransAlta’s debt have been fixed.
The income tax rate can change depending on the mix of earnings from various countries. Increased operating income will incur income tax expense at a rate of approximately 35 per cent compared to the forecasted overall rate of approximately 25 per cent.
C R I T I C A L A C C O U N T I N G P O L I C I E S A N D E S T I M AT E S
The selection and application of accounting policies is an important process that has developed as TransAlta’s business activities have evolved and as accounting rules have changed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment relative to the circumstances existing in the corporation’s business. Every effort is made to comply with all applicable rules on or before the effective date, and TransAlta believes the proper implementation and consistent application of accounting rules is critical. However, not all situations are specifically addressed in the accounting literature. In these cases, the corporation’s best judgment is used to adopt a policy for accounting for these situations. This is accomplished by analogizing to similar situations and the accounting guidelines governing them, consideration of foreign accounting standards and consultation with the corporation’s independent auditors about the appropriate interpretation and application of these policies. Each of the critical accounting policies involves complex situations and a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact the corporation’s consolidated financial statements.
TransAlta’s significant accounting policies are described inNote 1to the consolidated financial statements. The most critical of these policies are those related to revenue recognition, PP&E, goodwill, asset retirement obligations, income taxes and employee future benefits(Notes 1(C), (F), (G), (I), (L) and (M), respectively). Each policy involves a number of estimates and assumptions to be made by management about matters that are highly uncertain at the time the estimate is made. Different estimates, with respect to key variables the corporation used for the calculations, or changes to estimates could potentially have a material impact on TransAlta’s financial position or results of operations. These critical accounting estimates are described below.
Management has discussed the development and selection of these critical accounting estimates with the A&E Committee and the corporation’s independent auditors. The A&E Committee has reviewed and approved the corporation’s disclosure relating to critical accounting estimates in this MD&A.
Tables are provided in the following discussion to reflect the sensitivities associated with changes in key assumptions used in the estimates. The tables reflect an increase or decrease in the percentage or other factor for each assumption. The inverse of each change is generally expected to have a similar opposite impact. Each separate item in the sensitivity assumes all other factors remain constant.
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 5 5
Revenue Recognition
The majority of the corporation’s revenues are derived from the sale of physical power and from energy marketing and trading activities. Revenues under long-term electricity and thermal sales contracts generally include one or more of the following components: fixed capacity payments for being available; energy payments for generation of electricity; availability incentives or penalties for exceeding or not meeting availability targets; excess energy payments for power generation above committed capacity; and ancillary services. Each is recognized upon output, delivery or satisfaction of specific targets, as specified by contractual terms. Revenues from non-contracted capacity are comprised of energy payments for each MWh produced at market prices, and are recognized upon delivery.
Trading activities use derivatives such as physical and financial swaps, forward sales contracts, futures contracts and options, which are used to earn trading revenues and to gain market information. These derivatives are accounted for using fair value accounting. Derivatives, other than real-time physical contracts, are presented on a net basis in the statements of earnings. The initial recognition of fair value and subsequent changes in fair value affect reported earnings in the period the change occurs. The fair values of those instruments that remain open at the balance sheet date represent unrealized gains or losses and are presented on the balance sheets as price risk management assets and liabilities. Non-derivative contracts are accounted for using the accrual method. To be consistent with the EITF 03-11, TransAlta has concluded that real-time physical contracts meet the definition of derivative contracts held for delivery and therefore realized gains and losses are reported gross in the statement of earnings.
The determination of the fair value of energy trading contracts and derivative instruments is complex and relies on judgments concerning future prices, volatility and liquidity, among other factors. The majority of derivatives traded by TransAlta have quoted market prices or over-the-counter quotes are available from brokers. However, some derivatives are not traded on an active exchange or extend beyond the time period for which exchange-based quotes are available. These derivatives require the use of internal valuation techniques or models (mark-to-model accounting).
Mark-to-model accounting is currently used for physical and financial forward contracts and option contracts on transmission and transmission congestion. Accrual accounting is used for transmission rights acquired to sell production from TransAlta plants, and physical transmission rights used by the Energy Marketing segment. Changes in fair value of derivatives subsequent to inception are recorded on the balance sheet as price risk management assets or liabilities with the offset recorded in revenues. The values can be favourable or unfavourable, and depending on current market conditions, values can fluctuate significantly, with the effect of changes being recorded through earnings in the period of the change. Modeling techniques require the corporation to model future prices, price correlation, market volatility, liquidity and other forecasted market intelligence, as well as the use of mathematical extrapolation techniques. Where appropriate, the estimates used to derive fair value reflect the potential impact for uncertainties in the modeling process, the potential impact of liquidating the corporation’s position in an orderly manner over a reasonable period of time under present market conditions and operational risk. TransAlta validates its mark-to-model results by comparing against settled data. The amounts reported in the financial statements may change as estimates are revised to reflect actual results or new information, changes in market conditions or other factors, many of which are beyond the control of the corporation, and may be material.
Key variables used in the models are uncertain. The estimated value of these contracts at Dec. 31, 2004 using mark-to-model methodology was $3.5 million. Sensitivities of the valuation, which would have been recorded in earnings in the current year, are as follows:
Impact on | |||||
Change in | pre-tax | ||||
Assumption | assumption | earnings | |||
Change in volatility | 1% | $ | 1.1 | ||
Change in commodity price | 1% | 3.7 | |||
There have been no significant changes to the modeling techniques in the past three years.
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Valuation of Property, Plant and Equipment
PP&E makes up 78 per cent of the corporation’s assets, of which 99 per cent relates to the Generation segment. On an annual basis, and when indicators of impairment exist, TransAlta determines whether the net carrying amount of PP&E is recoverable from future undiscounted cash flows. Factors which could indicate that an impairment exists include significant underperformance relative to historical or projected operating results, significant changes in the manner or use of the assets, the strategy for the corporation’s overall business and significant negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired. This can be further complicated in situations where TransAlta is not the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their occurrence.
The corporation’s businesses, the markets and business environment are continually monitored, and judgments and assessments are made to determine whether an event has occurred that indicates possible impairment. If such an event has occurred, an estimate is made of the future undiscounted cash flows from the asset. If the total of the undiscounted future cash flows excluding financing charges, with the exception of plants that have specifically dedicated debt, is less than the carrying amount of the asset, an asset impairment charge must be recognized in the financial statements. The amount of the impairment recognized is calculated by subtracting the fair value of the asset from the carrying value of the asset. Fair value is the amount at which an item could be bought or sold in a current transaction between willing parties, and is best estimated by calculating the net present value of future expected cash flows related to the asset. Both the identification of events that may trigger an impairment and the estimates of future cash flows and the fair value of the asset require considerable judgment.
The assessment of asset impairment requires management to make significant assumptions about future sales prices, cost of sales, production and fuel consumed over the life of the plants (up to 30 years), retirement costs and discount rates. In addition, when impairment tests are performed, the estimated useful lives of the plants are reassessed, with any change accounted for prospectively.
In estimating future cash flows of the plants, the corporation uses estimates of contracted and future market prices based on expected market supply and demand in the region in which the plant operates, anticipated production levels, planned and unplanned outages, and transmission capacity or constraints for the remaining life of the plant. Actual results can, and often do, differ from the estimates, and can have either a positive or negative impact on the estimate of the impairment charge, and may be material.
The results of TransAlta’s annual impairment review for all plants showed no indications of impairment in 2004. Had assumptions been made that resulted in future cash flows of the plants declining by 10 per cent, certain of TransAlta’s plants would have been impaired at Dec. 31, 2004.
During 2003, the Binghamton plant did not run on a regular basis. This indicated that an impairment may have existed; therefore the plant was reviewed for impairment. The Binghamton plant sells electricity to the New York area at spot market rates when such prices exceed its marginal operating costs of producing electricity. The corporation determined that undiscounted expected future cash flows from the Binghamton plant were less than the carrying value of the asset; therefore a pre-tax impairment charge of $5.6 million was recognized in the fourth quarter of 2003.
The fair value of the Binghamton plant was calculated from the expected present value of future cash flows. Management was required to make several estimates of future results and events. The range of pre-tax impairment charges resulting from management’s estimates was from $3.1 million to $8.1 million.
In the second quarter of 2003, TransAlta determined that future growth would be slower than previously anticipated. This reduction in expansion plans, combined with an unsuccessful bid for the Valladolid project in Mexico, indicated that an impairment of TransAlta’s turbine inventory may exist. As a result, the turbine inventory was reviewed for impairment. The corporation concluded that the carrying amount of the turbine inventory was not recoverable and the fair value of the turbines was less than the carrying value of the assets; therefore an $84.7 million asset impairment charge was recognized. Fair value was estimated using market prices for the same or similar turbines.
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 5 7
Asset Retirement Obligations
The corporation recognizes asset retirement obligations for PP&E in the period in which they are incurred if a reasonable estimate of a fair value can be determined. The fair value of the liability is described as the amount at which the liability could be settled in a current transaction between willing parties. Expected values are probability weighted to deal with the risks and uncertainties inherent in the timing and amount of settlement of many asset retirement obligations. Expected values are discounted at the risk-free interest rate adjusted to reflect the market’s evaluation of the entity’s credit standing. Determining asset retirement obligations requires estimating the life of the related asset and the costs of activities such as demolition, dismantling, restoration and remedial work based on present-day methods and technologies.
At Dec. 31, 2004, the asset retirement obligations recorded on the consolidated balance sheet were $243.4 million. TransAlta estimates the undiscounted amount of cash flow required to settle the asset retirement obligations is approximately $1.3 billion, which will be incurred between 2005 and 2072. The majority of the costs will be incurred between 2020 and 2030. A discount rate of eight per cent was used to calculate the carrying value of the asset retirement obligations.
Sensitivities for the major assumptions are as follows:
Impact on | |||||
Change in | pre-tax | ||||
Assumption | assumption | earnings | |||
Discount rate | 1% | $ | 2.6 | ||
Undiscounted asset retirement obligations | 1% | 0.2 | |||
Useful Life of Property, Plant and Equipment (PP&E)
PP&E is depreciated over its estimated useful life. Estimated useful lives were determined based on current facts and past experience, and take into consideration the anticipated physical life of the asset, existing long-term sales agreements and contracts, current and forecasted demand and the potential for technological obsolescence. Major components of plants are depreciated over their own useful lives. A component is a tangible asset that can be separately identified as an asset, and is expected to provide a benefit of greater than one year.
Depreciation and amortization expense was $377.3 million in 2004, of which $53.3 million relates to mining equipment, and is included in fuel and purchased power.
The rates used are reviewed on an ongoing basis to ensure they continue to be appropriate, and are also reviewed in conjunction with impairment testing, as discussed above.
A five per cent change in the estimated useful life of depreciable assets will result in a change of $17.6 million in depreciation and amortization expense.
Valuation of Goodwill
The corporation evaluates goodwill for impairment at least annually, or more frequently if indicators of impairment exist. If the carrying value of a reporting unit including goodwill exceeds the reporting unit’s fair value, any excess represents the impairment loss.
Goodwill was recorded on the acquisitions of Merchant Energy Group of the Americas (MEGA), Vision Quest and CE Gen. At Dec. 31, 2004, this goodwill had a total carrying value of $142.2 million.
The corporation reviewed the goodwill in the fourth quarter of 2004 in connection with the corporation’s annual impairment tests. To test for impairment, the fair value of the reporting units to which the goodwill relates were compared to the carrying values of the reporting units. The corporation determined that the fair values of the reporting units, based on historical cash flows and estimates of future cash flows, exceeded their carrying values; therefore, no impairment charges were recorded.
Determining the fair value of the reporting units is susceptible to changes from period to period as management is required to make assumptions about future cash flows, production and trading volumes, margins and fuel and operating costs. Had assumptions been made that resulted in fair values of the reporting units declining by 10 per cent from current levels, there would not have been any impairment of goodwill. To the extent goodwill was impaired, the impairment charge would impact earnings in the period of the charge.
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Income Taxes
In accordance with Canadian GAAP, the corporation uses the liability method of accounting for future income taxes and provides future income taxes for all significant income tax temporary differences.
Preparation of the consolidated financial statements requires an estimate of income taxes in each of the jurisdictions in which the corporation operates. The process involves an estimate of the corporation’s actual current tax exposure and an assessment of temporary differences resulting from differing treatment of items, such as depreciation and amortization, for tax and accounting purposes. These differences result in future tax assets and liabilities that are included in the corporation’s consolidated balance sheet.
An assessment must also be made to determine the likelihood that the corporation’s future tax assets will be recovered from future taxable income. To the extent that recovery is not considered likely, a valuation allowance must be determined. Judgment is required in determining the provision for income taxes, future income tax assets and liabilities and any related valuation allowance. To the extent a valuation allowance is created or revised, current period earnings will be affected.
Future tax assets of $153.5 million have been recorded on the consolidated balance sheet at Dec. 31, 2004. This is comprised primarily of unrealized losses on electricity trading contracts, asset retirement obligation costs and net operating and capital loss carryforwards. The corporation believes there will be sufficient taxable income and capital gains that will permit the use of these deductions and carryforwards in the tax jurisdictions where they exist.
Future tax liabilities of $715.0 million have been recorded on the consolidated balance sheet at Dec. 31, 2004. The liability is comprised primarily of unrealized gains on electricity trading contracts and income tax deductions in excess of related depreciation of PP&E.
Judgment is required to assess tax interpretations, regulations and legislation, which are continually changing, to ensure liabilities are complete and to ensure assets, net of valuation allowances, are realizable. The impact of different interpretations and applications could potentially be material.
The corporation’s tax filings are subject to audit by taxation authorities. The outcome of some audits may change the tax liability of the corporation, although management believes that it has adequately provided for income taxes based on all information currently available. The outcome of the audits is not known, nor is the potential impact on the financial statements determinable.
Employee Future Benefits
As explained inNote 18to the consolidated financial statements, the corporation provides post-retirement benefits to employees. The cost of providing these benefits is dependent upon many factors that result from actual plan experience and assumptions of future experience.
The liability for future benefits and associated pension costs included in annual compensation expenses are impacted by employee demographics, including age, compensation levels, employment periods, the level of contributions made to the plans and earnings on plan assets. Changes to the provisions of the plans may also affect current and future pension costs. Pension costs may also be significantly impacted by changes in key actuarial assumptions, including anticipated rates of return on plan assets and the discount rates used in determining the projected benefit obligation and pension costs.
The plan assets are comprised primarily of equity and fixed income investments. Fluctuations in actual equity market returns and changes in interest rates may result in increased or decreased pension costs in future periods.
The following chart reflects the sensitivities associated with a change in certain actuarial assumptions:
Impact on | Impact on | |||||||
projected | pension cost | |||||||
Change in | benefit | reported | ||||||
Actuarial assumption | assumption | obligation | in earnings | |||||
Discount rate | 1% | $ | 43.4 | $ | 2.0 | |||
Rate of return on plan assets | 1% | – | 3.3 | |||||
The discount rate used represents high-quality fixed income securities currently available and expected to be available during the period to maturity of the pension benefits. The corporation does not expect to make any changes to the rate in 2005.
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 5 9
The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments held by the plan. For the year ended Dec. 31, 2004, the plan assets had a return of $33.4 million compared to a return of $36.6 million in 2003 and a loss of $6.7 million in 2002. The 2004 actuarial valuation used the same rate of return on plan assets (7.1 per cent) as was used in 2003 and 2002.
As a result of the corporation’s plan asset return experience for its U.S. registered pension plan, at Dec. 31, 2004, the corporation was required under U.S. GAAP to recognize an additional minimum liability(Note 26 to the consolidated financial statements).The liability was recorded as a reduction in common equity through a charge to other comprehensive income (OCI), and did not affect net income for 2004.
The amount of the additional pension liability recognized for U.S. GAAP depended on a number of factors, including the discount rate and asset returns experienced, contributions made by the corporation and any resulting change in management’s assumptions. Pension cost and cash funding requirements could increase in future years.
N O N - G A A P M E A S U R E S
TransAlta evaluates its performance and the performance of its business segments using a variety of measures. Those discussed below are not defined under GAAP and therefore should not be considered in isolation or as an alternative to, or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP as an indicator of the corporation’s financial performance or liquidity. These measures are not necessarily comparable to a similarly titled measure of another company.
Each business unit assumes responsibility for its operating results measured to operating income. Operating income is a measure of financial performance used by TransAlta’s analysts and investors to analyze and compare companies on the basis of operating performance.
Gross margin less operating expenses and operating income provide management with a measurement of operating performance that is readily comparable from period to period.
Gross margin less operating expenses and operating income are reconciled to net earnings below:
Year ended Dec. 31 | 2004 | 20031 | 20021 | ||||||
Gross margin | $ | 1,409.3 | $ | 1,356.1 | $ | 1,059.3 | |||
Operating expenses | (970.8) | (921.4) | (690.9) | ||||||
438.5 | 434.7 | 368.4 | |||||||
Gain on sale of Sheerness Generating Station | – | 191.5 | – | ||||||
Gain on sale of Meridian Cogeneration facility | 17.7 | – | – | ||||||
Gain on sale of TransAlta Power partnership units | 44.8 | 15.2 | – | ||||||
Gain on sale of land | – | 10.5 | – | ||||||
Asset impairment charges | – | (90.3) | (152.5) | ||||||
Prior period regulatory decision | (22.9) | – | (3.3) | ||||||
Operating income | 478.1 | 561.6 | 212.6 | ||||||
Other income | – | (3.2) | 0.1 | ||||||
Foreign exchange gain (loss) | 0.7 | (4.7) | 1.2 | ||||||
Net interest expense | (222.1) | (220.7) | (117.6) | ||||||
Earnings before non-controlling interests and income taxes | 256.7 | 333.0 | 96.3 | ||||||
Non-controlling interests | 46.0 | 34.2 | 20.1 | ||||||
Earnings before income taxes | 210.7 | 298.8 | 76.2 | ||||||
Income tax expense | 50.1 | 64.6 | 9.4 | ||||||
Earnings from continuing operations | 160.6 | 234.2 | 66.8 | ||||||
Earnings from discontinued operations, net of tax | – | – | 12.8 | ||||||
Gain on disposal of discontinued operations, net of tax | 9.6 | – | 120.0 | ||||||
Net earnings | $ | 170.2 | $ | 234.2 | $ | 199.6 | |||
1 | TransAlta early adopted the amended standard on the presentation of liabilities and equity on Jan. 1, 2004. SeeNote 1to the unaudited interim consolidated financial statements for further discussion. Prior periods have been restated. |
Presenting earnings on a comparable basis from period to period provides management with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. To do so, the following items, which we believe would otherwise affect the comparability of TransAlta’s operating results from period to period, are excluded from net earnings: gains on sale of the Sheerness Generating Station, TransAlta Power units, the Meridian Cogeneration Facility and land, asset impairment charges, prior period regulatory decisions, and earnings from discontinued operations, net of tax.
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Earnings presented on a comparable basis from period to period is reconciled to net earnings below:
Year ended Dec. 31 | 2004 | 2003)1 | 2002)1 | ||||||
Earnings on a comparable basis | $ | 134.9 | $ | 128.7 | $ | 168.0 | |||
Gain on sale of Sheerness Generating Station, net of tax | – | 145.8 | – | ||||||
Gain on sale of Meridian Cogeneration facility, net of tax | 11.5 | – | – | ||||||
Gain on sale of TA Power units, net of tax | 29.1 | 10.1 | – | ||||||
Gain on sale of land, net of tax | – | 8.6 | – | ||||||
Asset impairment charges, net of tax | – | (59.0) | (99.1) | ||||||
Prior period regulatory decision, net of tax | (14.9) | – | (2.1) | ||||||
Earnings from discontinued operations, net of tax | – | – | 12.8 | ||||||
Gain from discontinued operations, net of tax | 9.6 | – | 120.0 | ||||||
Net earnings | $ | 170.2 | $ | 234.2 | $ | 199.6 | |||
Weighted average common shares outstanding in the period | 192.7 | 185.3 | 169.6 | ||||||
Earnings on a comparable basis per share | $ | 0.70 | $ | 0.69 | $ | 0.99 | |||
1 | TransAlta early adopted the amended standard on the presentation of liabilities and equity on Jan. 1, 2004. SeeNote 1to the unaudited interim consolidated financial statements for further discussion. Prior periods have been restated. |
S E L E C T E D Q UA R T E R LY I N F O R M AT I O N
| |||||||||||||
(Unaudited, in millions of Canadian dollars except per share amounts) | |||||||||||||
2004 Quarters | First | Second | Third | Fourth | |||||||||
Revenue | $ | 712.7 | $ | 670.1 | $ | 743.0 | $ | 712.5 | |||||
Earnings from continuing operations | 47.2 | 15.5 | 35.8 | 62.1 | |||||||||
Net earnings | 47.2 | 25.1 | 35.8 | 62.1 | |||||||||
Basic earnings per common share | |||||||||||||
Continuing operations | 0.25 | 0.08 | 0.18 | 0.32 | |||||||||
Net earnings | 0.25 | 0.13 | 0.18 | 0.32 | |||||||||
Diluted earnings per common share | |||||||||||||
Continuing operations | 0.24 | 0.08 | 0.18 | 0.32 | |||||||||
Net earnings | 0.24 | 0.13 | 0.18 | 0.32 | |||||||||
2003 Quarters | First | Second | Third | Fourth | |||||||||
Revenue | $ | 639.5 | $ | 563.0 | $ | 656.9 | $ | 661.5 | |||||
Earnings from continuing operations | 48.7 | 23.3 | 118.4 | 43.8 | |||||||||
Net earnings | 48.7 | 23.3 | 118.4 | 43.8 | |||||||||
Basic earnings per common share | |||||||||||||
Continuing operations | 0.28 | 0.12 | 0.62 | 0.23 | |||||||||
Net earnings | 0.28 | 0.12 | 0.62 | 0.23 | |||||||||
Diluted earnings per common share | |||||||||||||
Continuing operations | 0.28 | 0.12 | 0.62 | 0.23 | |||||||||
Net earnings | 0.28 | 0.12 | 0.62 | 0.23 | |||||||||
TransAlta’s results are partly seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are ordinarily incurred in the second and third quarters when electricity prices are expected to be lower, as electricity prices generally increase in the winter months in the Canadian market. Margins are also typically impacted in the second quarter due to the volume of hydro production resulting from spring runoff and rainfall in the Canadian and U.S. markets. TransAlta’s results reflect the completion, acquisition and disposition of plants and facilities throughout 2002, 2003 and 2004 as described previously within this MD&A.
M a n a g e m e n t ’s D i s c u s s i o n & A n a l y s i s 6 1