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Q3:2004
M A N A G E M E N T ' S D I S C U S S I O N A N D A N A L Y S I S
This management's discussion and analysis (MD&A) should be read in conjunction with the unaudited interim consolidated financial statements of TransAlta Corporation (TransAlta or the corporation) as at and for the three and nine months ended Sept. 30, 2004 and 2003, and should also be read in conjunction with the audited consolidated financial statements and MD&A contained in TransAlta's annual report for the year ended Dec. 31, 2003. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP). All tabular amounts in the following discussion are in millions of Canadian dollars unless otherwise noted. This MD&A is dated Oct. 20, 2004. Additional information respecting TransAlta, 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 T A T 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, 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 standards issued by Canadian and U.S. standard setters. Given these uncertainties, the reader should not place undue reliance on these forward-looking statements.
R E S U L T S O F O P E R A T 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 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.
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 individual items is reflected in the cumulative translation account on the consolidated balance sheet.
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H I G H L I G H T S | ||||||
The following table depicts key financial results and statistical operating data: | ||||||
3 months ended Sept. 30 | 2004 | 2003 1 | ||||
Availability (%) | 88.4 | 88.8 | ||||
Production (GWh) | 13,529 | 13,687 | ||||
Electricity trading volumes (GWh) | 25,280 | 23,655 | ||||
Gas trading volumes (million GJ) | 130.8 | 70.1 | ||||
Revenue | $ | 743.0 | $ | 656.9 | ||
Gross margin | $ | 366.3 | $ | 351.5 | ||
Operating income 2 | $ | 115.7 | $ | 210.2 | ||
Net earnings | $ | 35.8 | $ | 118.4 | ||
Basic earnings per common share: | ||||||
Earnings from continuing operations | $ | 0.18 | $ | 0.62 | ||
Net earnings | $ | 0.18 | $ | 0.62 | ||
Diluted earnings per common share: | ||||||
Earnings from continuing operations | $ | 0.18 | $ | 0.62 | ||
Net earnings | $ | 0.18 | $ | 0.62 | ||
Cash flow from operating activities | $ | 190.6 | $ | 138.1 | ||
9 months ended Sept. 30 | 2004 | 2003 1 | ||||
Availability (%) | 88.8 | 90.3 | ||||
Production (GWh) | 40,648 | 39,246 | ||||
Electricity trading volumes (GWh) | 61,269 | 68,092 | ||||
Gas trading volumes (million GJ) | 313.6 | 164.4 | ||||
Revenue | $ | 2,125.8 | $ | 1,859.4 | ||
Gross margin | $ | 1,063.6 | $ | 1,002.9 | ||
Operating income 2 | $ | 328.8 | $ | 432.9 | ||
Earnings from continuing operations | $ | 98.5 | $ | 190.4 | ||
Gain on disposal of discontinued operations, net of tax | 9.6 | - | ||||
Net earnings | $ | 108.1 | $ | 190.4 | ||
Basic earnings per common share: | ||||||
Earnings from continuing operations | $ | 0.51 | $ | 1.04 | ||
Net earnings | $ | 0.56 | $ | 1.04 | ||
Diluted earnings per common share: | ||||||
Earnings from continuing operations | $ | 0.51 | $ | 1.04 | ||
Net earnings | $ | 0.56 | $ | 1.04 | ||
Cash flow from operating activities | $ | 454.8 | $ | 564.6 | ||
1 | TransAlta early adopted the amended standard on the presentation of liabilities and equity on Jan. 1, 2004. See Note 1 to the unaudited interim consolidated financial statements for further discussion. Prior periods have been restated. |
2 | For reconciliation of operating income, see page three of this MD&A. |
In the three months ended Sept. 30, 2004, availability decreased slightly compared to the same period in 2003. Production decreased slightly as a result of unplanned outages at Centralia offset by decreased planned maintenance at Alberta Thermal plants and by incremental production from the Chihuahua plant.
For the nine months ended Sept. 30, 2004, availability decreased to 88.8 per cent from 90.3 per cent in the same period in 2003 primarily due to unplanned outages at the Mexican plants in the first quarter and higher planned maintenance at the Sheerness and Centralia plants in the second quarter.
Total electricity volumes of proprietary trading transactions in the three months ended Sept. 30, 2004 are slightly above, but consistent with, the same period in 2003. For the nine months ended Sept. 30, 2004, electricity volumes were lower than the same period in 2003 due to the elimination of trading in New York transmission congestion contracts (TCC) in 2003. The
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increase in gas volumes for both the three and nine month periods ending Sept. 30, 2004, relates to the increased use of heat rate contracts, which involve a gas component, to manage power price risk in electricity trading.
In the three months ended Sept. 30, 2004, gross margin was $14.8 million higher than for the same period of 2003 primarily as a result of reduced penalties related to planned maintenance, the effect of the Wabamun plant becoming merchant, increased hydro volumes and incremental gross margins at the Chihuahua plant partially offset by decreased margins at CE Generation LLC (CE Gen).
In the nine months ended Sept. 30, 2004, gross margin increased by $60.7 million compared to the same period in 2003 as a result of the incremental margin from the Mexican plants, the effect of the Wabamun plant becoming merchant, an improvement in lost margin due to planned maintenance and higher Energy Marketing gross margins, partially offset by decreased hydro volumes. In addition, a $33.3 million TCC loss was recognized in the second quarter of 2003. Further discussion of the TCC loss is included in Significant Events in this MD&A.
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 reconciliation to net earnings.
Operating income for the three and nine months ended Sept. 30, 2004, decreased, by $94.5 million and $104.1 million, respectively, compared to the similar periods in 2003. Operating income for the three and nine months ended Sept. 30, 2004, is reconciled to operating income for the same periods in 2003, as shown below:
Operating income for 3 months ended Sept. 30, 2003 | $ | 210.2 | |
Increased Generation gross margins | 10.6 | ||
Decreased major maintenance costs and lost earnings due to planned outages | 7.8 | ||
Lower Energy Marketing gross margins | (2.5) | ||
Decrease in operational and administrative costs | 1.1 | ||
Increased depreciation | (2.9) | ||
Lower CE Gen operating income | (4.8) | ||
2004 gain on sale of TransAlta Power partnership units | 3.1 | ||
2003 gain on sale of Sheerness Generating Station | (191.5) | ||
2003 Turbine impairment | 84.7 | ||
Other | (0.1) | ||
Operating income for 3 months ended Sept. 30, 2004 | $ | 115.7 | |
Operating income for 9 months ended Sept. 30, 2003 | $ | 432.9 | |
Increased Generation gross margins | 7.4 | ||
Decreased major maintenance costs and lost earnings due to planned outages | 17.1 | ||
Higher Energy Marketing gross margins | 10.1 | ||
Increase in operational and administrative costs | (8.4) | ||
Increased depreciation | (30.6) | ||
Lower CE Gen operating income | (16.6) | ||
2003 Energy Marketing TCC loss | 33.3 | ||
Increase to California provision | (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) | ||
2004 gain on sale of TransAlta Power partnership units | 24.2 | ||
2003 Turbine impairment | 84.7 | ||
Other | (0.8) | ||
Operating income for 9 months ended Sept. 30, 2004 | $ | 328.8 | |
In the three months ended Sept. 30, 2004, operations, maintenance and administration (OM&A) expenses were comparable to the same period in 2003. In the nine months ended Sept. 30, 2004, OM&A costs increased by $21.8 million compared to the same period in 2003 due in part to incremental operating costs related to the Mexican and Sarnia plants and increased planned maintenance. 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).
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In the three months ended Sept. 30, 2004, depreciation costs increased by $4.7 million partly due to incremental depreciation from the Chihuahua plant and capital spending on planned maintenance. In the first nine months of 2004, depreciation expense increased by $37.3 million primarily due to incremental depreciation from the Chihuahua, Campeche and Sarnia plants.
In the first quarter of 2004, an additional $22.9 million pre-tax provision was made against outstanding Energy Marketing receivables related to energy sales in California in 2000 and 2001.
An income tax expense of $11.7 million was recorded in the third quarter of 2004 compared to an expense of $26.6 million in the same period in 2003. The decrease is due to lower pre-tax earnings offset by an increase in effective tax rates. The effective tax rate for the three months ended Sept. 30, 2004 is higher than the same period in 2003 due to the impact of the gain on the sale of the Sheerness plant which was partially offset by the tax effect of the asset impairment charges. The year to date expense of $23.8 million is $31.3 million lower than the comparable period due to a decrease in pre-tax earnings, a decrease in the effective tax rate 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 favorable settlement from the New Zealand Inland Revenue relating to the 1999 taxation year. The effective income tax rate for the first nine months of 2004 is lower than the same period in 2003 due to the New Zealand income tax recovery as well as the reasons discussed above for the current quarter.
In June 2004, TransAlta finalized the settlement of the April 2002 sale of the former Transmission operations. As a result of this settlement, a $9.6 million after-tax gain on disposal of discontinued operations was recorded. The total gain on the sale of the Transmission operations recorded in the second quarter and prior periods was $129.6 million.
Earnings per share from continuing operations of $0.18 for the three months ended Sept. 30, 2004 was $0.44 lower than the same period in 2003. Earnings per share from continuing operations of $0.51 for the nine months ended Sept. 30, 2004 was $0.53 lower than the same period in 2003. The decrease in both periods was primarily due to the gain on the sale of Sheerness in the third quarter of 2003, partially offset by the turbine impairment.
Cash flow from operating activities for the three months ended Sept. 30, 2004 was $190.6 million compared to $138.1 million for the same period in 2003 as a result of an improved working capital position from a reduction in income tax receivable following the finalization of the sale of the Distribution and Retail (D&R) operations offset by reductions in payables and slightly lower earnings. For the nine months ended Sept. 30, 2004, cash flow from operating activities was $454.8 million, compared to $564.6 million in the same periods in 2003 due to payments of tax installments, insurance premiums and unrealized gains on the valuation of trading activities.
The corporation's financial reporting procedures and practices have enabled the certification of TransAlta's third quarter report to shareholders in voluntary compliance with the requirements of Section 302 of the Sarbanes-Oxley Act and in compliance with the requirements of Multilateral Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings".
S I G N I F I C A N T E V E N T S
Three months ended Sept. 30, 2004 and 2003
Summerview Wind Farm
Late in the third quarter, the Summerview Wind Farm began commercial production. The 68 megawatt (MW) wind farm is operated by Vision Quest Windelectric.
Alberta D&R Operations
In Sept. 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.
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Asset impairment charges
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 a pre-tax $84.7 million impairment charge ($55.4 million after-tax) in the third quarter of 2003 to write down the turbines to fair value.
Sale of 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 plant to TransAlta Cogeneration, L.P. (TA Cogen) for $630.0 million. TA Cogen is owned 50.01 per cent by TransAlta and 49.99 per cent by TransAlta Power, L.P. (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 to 10.0 per cent as at Sept. 30, 2004 and increasing cash proceeds by a further $96.6 million.
In connection with the sale, 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 $119.0 million (pre-tax) 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.
As a result of the sale, TransAlta realized a pre-tax gain on sale of $191.5 million ($145.8 million after-tax) recorded in the third quarter of 2003, which includes the realization of the approximate $119.0 million 1998 deferred gain. Additional gains recorded on the exercise of warrants and sale of TransAlta Power units by TransAlta to TransAlta Power totaled $39.4 million of which $3.1 million related to the third quarter of 2004. Proceeds from the sale of Sheerness were used to repay debt.
Nine months ended Sept. 30, 2004 and 2003
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.
Energy Marketing loss on transmission congestion contracts (TCCs)
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.
Equity offering
In March and April of 2003, the corporation issued a total of 17.25 million common shares for gross proceeds of $276.0 million.
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Acquisitions
In January 2003, the corporation purchased a 50 per cent interest in CE Gen. Note 2 of the unaudited interim 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 Utilities Inc.'s (EPCOR) 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.
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 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. TransAlta expects to collect the remaining US$5.4 million within the next 12 months.
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 filed a petition with FERC designed to address potential relief from all or a portion of the refund liability. 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 are recorded when the effect of such decisions are known, without adjustment to the financial statements of prior periods.
N E W A C C O U N T I N G S T A N D A R D S
The Canadian Institute of Chartered Accountants has amended the standard on the presentation of liabilities and equity effective for years beginning on or after Nov. 1, 2004. 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 early adopted this standard effective Jan. 1, 2004 and has therefore included the corporation's preferred securities as financial liabilities on the consolidated balance sheets. Preferred securities distributions are included in interest expense on the consolidated statement of earnings and are therefore included as a deduction in arriving at net earnings. Prior periods have been restated.
Effective Jan. 1, 2004, TransAlta has elected to present employee share purchase plan loans as a deduction from shareholders' equity. The presentation of prior periods has been reclassified. The impact of this new accounting treatment is immaterial to the consolidated financial statements.
Effective June 1, 2004, TransAlta has elected to present assets related to mineral rights as tangible assets. TransAlta's acquired coal rights were previously disclosed as intangible assets. Coal rights are now classified as property, plant and equipment and prior periods' presentation has been reclassified. The impact of this new accounting treatment is immaterial to the consolidated financial statements.
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D I S C U S S I O N O F S E G M E N T E D R E S U L T S
GENERATION: Owns and operates hydro, wind, geothermal, gas- and coal-fired plants and related mining operations in Canada, the U.S., Mexico and Australia. At Sept. 30, 2004, Generation had 8,804 MW of gross generating capacity in operation (8,390 MW net ownership interest) and 225 MW under construction.
For the three months ended Sept. 30, 2004, availability decreased slightly to 88.4 per cent from 88.8 per cent in the same period in 2003. For the nine months ended Sept. 30, 2004, availability decreased to 88.8 per cent from 90.3 per cent in the same period 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.
The results of the Generation segment are as follows: | ||||||||||||
2004 | 2003 | |||||||||||
3 months ended Sept. 30 |
Total
Total
Total
Total
Generation's revenues are derived from the production of electricity and steam as well as ancillary services such as system support. Revenues are subject to seasonal variations. Gas and coal-fired facilities that have exposure to market fluctuations in energy commodity prices represent 5 per cent and 25 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 the Financial Accounting Standards Board (FASB) Statement 133.
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TransAlta's production volumes, electricity and steam production revenues and fuel and purchased power costs are presented below:
Fuel & | ||||||||||||||||||||
Fuel & | Purchased | Gross | ||||||||||||||||||
3 months ended | Production | Purchased | Gross | Revenue | Power | Margin | ||||||||||||||
Sept. 30, 2004 | (GWh) | Revenue | Power | Margin | per MWh | per MWh | per MWh | |||||||||||||
Alberta PPAs | 6,025 | $ | 156.1 | $ | 45.4 | $ | 110.7 | $ | 25.91 | $ | 7.54 | $ | 18.37 | |||||||
Long-term contracts | 2,537 | 199.5 | 130.9 | 68.6 | 78.64 | 51.60 | 27.04 | |||||||||||||
Merchant | 4,162 | 227.3 | 121.3 | 106.0 | 54.61 | 29.14 | 25.47 | |||||||||||||
CE Gen | 805 | 86.3 | 19.2 | 67.1 | 107.20 | 23.85 | 83.35 | |||||||||||||
TOTAL | 13,529 | $ | 669.2 | $ | 316.8 | $ | 352.4 | $ | 49.46 | $ | 23.42 | $ | 26.05 | |||||||
Fuel & | ||||||||||||||||||||
Fuel & | Purchased | Gross | ||||||||||||||||||
3 months ended | Production | Purchased | Gross | Revenue | Power | Margin | ||||||||||||||
Sept. 30, 2003 | (GWh) | Revenue | Power | Margin | per MWh | per MWh | per MWh | |||||||||||||
Alberta PPAs | 7,012 | $ | 167.0 | $ | 46.2 | $ | 120.8 | $ | 23.82 | $ | 6.59 | $ | 17.23 | |||||||
Long-term contracts | 2,307 | 166.1 | 101.4 | 64.7 | 72.00 | 43.95 | 28.05 | |||||||||||||
Merchant | 3,586 | 181.9 | 105.8 | 76.1 | 50.73 | 29.50 | 21.22 | |||||||||||||
CE Gen | 782 | 98.6 | 25.1 | 73.5 | 126.09 | 32.10 | 93.99 | |||||||||||||
TOTAL | 13,687 | $ | 613.6 | $ | 278.5 | $ | 335.1 | $ | 44.83 | $ | 20.35 | $ | 24.48 | |||||||
Fuel & | ||||||||||||||||||||
Fuel & | Purchased | Gross | ||||||||||||||||||
9 months ended | Production | Purchased | Gross | Revenue | Power | Margin | ||||||||||||||
Sept. 30, 2004 | (GWh) | Revenue | Power | Margin | per MWh | per MWh | per MWh | |||||||||||||
Alberta PPAs | 19,401 | $ | 516.8 | $ | 140.1 | $ | 376.7 | $ | 26.64 | $ | 7.22 | $ | 19.42 | |||||||
Long-term contracts | 7,804 | 625.8 | 413.8 | 212.0 | 80.19 | 53.02 | 27.17 | |||||||||||||
Merchant | 11,397 | 580.4 | 316.7 | 263.7 | 50.93 | 27.79 | 23.14 | |||||||||||||
CE Gen | 2,046 | 219.1 | 51.2 | 167.9 | 107.09 | 25.02 | 82.06 | |||||||||||||
TOTAL | 40,648 | $ | 1,942.1 | $ | 921.8 | $ | 1,020.3 | $ | 47.78 | $ | 22.68 | $ | 25.10 | |||||||
Fuel & | ||||||||||||||||||||
Fuel & | Purchased | Gross | ||||||||||||||||||
9 months ended | Production | Purchased | Gross | Revenue | Power | Margin | ||||||||||||||
Sept. 30, 2003 | (GWh) | Revenue | Power | Margin | per MWh | per MWh | per MWh | |||||||||||||
Alberta PPAs | 21,188 | $ | 566.6 | $ | 140.5 | $ | 426.1 | $ | 26.74 | $ | 6.63 | $ | 20.11 | |||||||
Long-term contracts | 5,868 | 461.2 | 285.7 | 175.5 | 78.60 | 48.69 | 29.91 | |||||||||||||
Merchant | 10,174 | 514.6 | 293.2 | 221.4 | 50.58 | 28.82 | 21.75 | |||||||||||||
CE Gen | 2,016 | 244.9 | 64.9 | 180.0 | 121.48 | 32.19 | 89.29 | |||||||||||||
TOTAL | 39,246 | $ | 1,787.3 | $ | 784.3 | $ | 1,003.0 | $ | 45.54 | $ | 19.98 | $ | 25.56 | |||||||
Alberta PPAs
Activities in 2004 for the Wabamun plant are now classified as merchant as production from the plant is being sold on the spot market. The Power Purchase Agreement (PPA) for the Wabamun plant expired on Dec. 31, 2003.
Production for the three and nine months ended Sept. 30, 2004 decreased by 987 gigawatt hours (GWh) and 1,787 GWh, respectively, compared to the same periods in 2003 primarily due to the Wabamun plant now being classified as merchant and higher unplanned outages at the remaining Alberta thermal plants partially offset by reduced planned maintenance.
Revenues for the three and nine months ended Sept. 30, 2004 decreased by $10.9 million and $49.8 million, respectively, compared to the same periods in 2003 due to the Wabamun plant now being classified as merchant ($22.6 million and $68.6 million respectively) partially offset by reduced penalties related to planned maintenance at the remaining Alberta plants offset by unplanned outages ($12.5 million and $24.0 million respectively).
Revenues per megawatt hour (MWh) for the three months ended Sept. 30, 2004 increased by $2.09 per MWh compared to the same periods in 2003 as a result of reduced penalties related to planned maintenance. Revenues per MWh were consistent with 2003 on a year-to-date basis.
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Total fuel and purchased power costs are comparable to the same period in 2003 for the three months ended Sept. 30, 2004 as the increases in coal costs of $4.2 million were offset by lower production volumes. Total fuel costs are comparable to the same period in 2003 for the nine months ended Sept. 30, 2004 for the same reasons noted above.
Fuel and purchased power increased by $0.95 per MWh for the three months ended Sept. 30, 2004 due to higher diesel prices, increased overburden removal costs and decreased volumes. Substantially all of the coal used for production under Alberta PPAs is from coal reserves owned by TransAlta. For the nine months ended Sept. 30, 2004, fuel costs increased by $0.59 per MWh compared to the same period in 2003 due to the reasons outlined above partially offset by lower power prices in the first quarter of 2004.
Long-term contracts
In the three and nine months ended Sept. 30, 2004, production increased by 230 GWh and 1,936 GWh, respectively, compared to the same periods in 2003. The increase for the three month period is primarily the result of the incremental production from the Chihuahua plant (247 GWh) and the increase for the nine month period is primarily the result of the incremental production at the Chihuahua and Campeche plants (1,709 GWh).
For the three months ended Sept. 30, 2004, revenues increased by $33.4 million primarily due to incremental production at the Chihuahua plant ($22.0 million) and increased natural gas costs which are passed on to the customer. Fuel and purchased power increased by $29.5 million primarily due to higher market prices for natural gas and incremental production from Chihuahua ($18.5 million).
On a per MWh hour basis, revenues for the three months ended Sept. 30, 2004 increased by $6.64 per MWh compared to the same period in 2003 as a result of the majority of the increased gas costs being passed through to the customer. Fuel and purchased power increased by $7.65 per MWh compared to the same period in 2003, primarily due to higher market prices for natural gas. Gross margin decreased by $1.01 per MWh compared to the same period of 2003 primarily due to the impact of the incremental production from the Chihuahua plant which has a lower margin than other long-term contracts.
For the nine months ended Sept. 30, 2004 gross margin increased by $36.5 million compared to the same period in 2003 due to the factors described above and incremental production from the Mexican plants.
On a per MWh basis, for the nine months ended Sept. 30, 2004, gross margin decreased by $2.74 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.
As shown in the above graphs, electricity average prices in Alberta were lower and Mid-Columbia were higher in the third quarter of 2004 compared to the same period in 2003, while Ontario prices were comparable to last year. Alberta power prices were lower in 2004 relative to 2003 due to lower demand related to cooler weather, fewer plant outages and transmission constraints on exports. Higher natural gas prices than last year contributed to the increase in Mid-Columbia prices. Spark spreads (power price less cost of gas consumed) in Alberta, Mid-Columbia and Ontario were lower, due to power
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prices not increasing at the same rate as gas prices in those markets. Electricity prices generally increase as a result of increased natural gas prices; however, they may not be completely correlated due to the existence of generation overcapac-ity in a specific market or other generation fuel sources in that market such as hydro or nuclear power.
In the third quarter of 2004, merchant production was 4,162 GWh, of which 1,879 GWh was contracted under short- to medium-term contracts. In the third quarter of 2003, merchant production was 3,586 GWh, of which 2,562 GWh was contracted. The increase in production was primarily due to the sale of uncontracted production from the Wabamun plant, partially offset by lower electricity production at Centralia and Sarnia. For the first nine months of 2004, merchant production was 11,397 GWh, of which 4,809 GWh was contracted. For the first nine months of 2003, merchant production was 10,174 GWh, of which 6,440 GWh was contracted. The increase in merchant production was due to the expiration of the PPA contract at Wabamun and incremental production from Sarnia in the first quarter, partially offset by decreased production at Centralia.
For the three months ended Sept. 30, 2004, merchant revenues increased by $45.4 million while fuel and purchased power increased by $15.5 million resulting in a gross margin increase of $29.9 million compared to the same period in 2003. The gross margin increases in both revenue and fuel costs were primarily due to incremental production from the Wabamun plant ($25.9 million) and improved hydro volumes ($6.0 million). On a per MWh basis for the three months ended Sept. 30, 2004, merchant revenues increased by $3.88 per MWh while fuel and purchased power decreased by $0.36 per MWh resulting in a gross margin increase of $4.25 per MWh compared to the same period in 2003.
For the nine months ended Sept. 30, 2004, merchant revenues increased by $65.8 million, fuel and purchased power increased by $23.5 million and gross margins increased by $42.3 million compared to the same period in 2003. These gross margin increases were due to incremental production from the Wabamun plant ($64.0 million) offset by a reduction in hydro revenue ($6.8 million) in the first two quarters of the year, and lower production and shrinking spark spreads at Centralia ($11.3 million). On a per MWh basis, merchant revenues increased by $0.35 per MWh while fuel and purchased power decreased by $1.03 per MWh resulting in a gross margin increase of $1.39 per MWh compared to the same period in 2003.
CE Gen
TransAlta's share of CE Gen's production for the three and nine months ended Sept. 30, 2004, increased slightly by 23 GWh and 30 GWh respectively compared to the same periods in 2003. This was the result of decreased production at the Power Resources facility following the expiration of the long-term contract in September 2003 more than offset by increased availability due to reduced planned maintenance.
In the three and nine months ended Sept. 30, 2004, revenues decreased by $18.89 per MWh and $14.39 per MWh, respectively, due to expiration of the Power Resources facility long-term contract and the strengthening of the Canadian dollar compared to the U.S. dollar. In the three and nine months ended Sept. 30, 2004, fuel and purchased power decreased by $8.25 per MWh and $7.17 per MWh, respectively, primarily due to lower production at the Power Resources facility and the strengthening of the Canadian dollar compared to the U.S. dollar.
Operations, maintenance and administration expense
In the three months ended Sept. 30, 2004, OM&A expenses increased by $5.0 million compared to the same period in 2003 primarily due to higher planned maintenance expenditures. The incremental OM&A from new plants in the current year has been offset by other savings.
In the nine months ended Sept. 30, 2004, OM&A expenses increased by $20.6 million compared to the same period in 2003 due in part to incremental operating costs related to the Mexican and Sarnia plants and increased planned maintenance. 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).
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Planned Maintenance
The table below shows the amount of planned maintenance capitalized and expensed in the three and nine months ended Sept. 30, 2004 and 2003, excluding CE Gen:
3 months ended Sept. 30 | 9 months ended Sept. 30 | |||||||||||
Planned maintenance expenditures | 2004 | 2003 | 2004 | 2003 | ||||||||
Capitalized | $ | 31.5 | $ | 6.9 | $ | 76.5 | $ | 30.8 | ||||
Expensed | 31.7 | 27.0 | 68.6 | 64.9 | ||||||||
$ | 63.2 | $ | 33.9 | $ | 145.1 | $ | 95.7 | |||||
In the three and nine months ended Sept. 30, 2004, there was 635 GWh and 1,966 GWh, respectively, of production lost due to planned maintenance compared to 715 GWh and 1,863 GWh lost in the three and nine months ended Sept. 30, 2003.
Depreciation and amortization
Depreciation and amortization increased by $4.6 million in the third quarter of 2004 compared to the same period in 2003 partly due to incremental depreciation from the Chihuahua plant ($2.2 million) and capitalized maintenance.
Depreciation and amortization increased by $39.4 million in the nine months ended Sept. 30, 2004, compared to the same period in 2003 due to incremental depreciation from the Mexican and Sarnia plants ($18.2 million) and CE Gen ($7.9 million) and increased depreciation at the Ottawa, Mississauga and Windsor-Essex plants ($6.0 million).
Taxes other than income taxes
For the three and nine months ended Sept. 30, 2004, taxes other than income taxes were consistent with the same period in 2003.
ENERGY MARKETING: Derives 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.
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 Emerging Issues Task Force (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 Purposes, 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: | ||||||||||||
3 months ended Sept. 30 | 9 months ended Sept. 30 | |||||||||||
2004 | 2003 | 2004 | 2003 | |||||||||
Revenues | $ | 73.8 | $ | 43.3 | $ | 183.7 | $ | 72.1 | ||||
Trading purchases | (59.9) | (26.9) | (140.4) | (72.2) | ||||||||
Gross margin | 13.9 | 16.4 | 43.3 | (0.1) | ||||||||
Operations, maintenance and administration | 1.6 | 4.7 | 5.0 | 9.1 | ||||||||
Depreciation and amortization | 0.6 | 0.8 | 1.5 | 2.4 | ||||||||
Operating expenses | 2.2 | 5.5 | 6.5 | 11.5 | ||||||||
Prior period regulatory decision | - | - | 22.9 | - | ||||||||
Corporate allocations | 1.7 | 1.8 | 6.3 | 5.9 | ||||||||
Operating income | $ | 10.0 | $ | 9.1 | $ | 7.6 | $ | (17.5) | ||||
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In the three months ended Sept. 30, 2004 gross margin decreased by $2.5 million while in the nine months ended Sept 30, 2004 gross margin increased by $43.4 million compared to the same periods 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 $10.1 million for the nine months ended Sept. 30, 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 three and nine months ended Sept. 30, 2004 increased by $33.0 million and $68.2 million, respectively, relative to the same periods in 2003. The increase from 2003 levels is primarily the result of increased activity relative to an energy services agreement, purchasing power on behalf of a customer to service retail load.
OM&A costs for the three and nine months ended Sept. 30, 2004 decreased $3.1 million and $4.1 million, respectively, relative to the same periods in 2003. During the second quarter of 2003, TransAlta re-evaluated trading strategies and as a result, in the third quarter of 2003, the corporation consolidated the Annapolis trading office with Calgary incurring $1.1 million of severance and exit costs. General spending reductions in 2004 relative to 2003 combined with a lower spend profile in the third quarter of 2004 contributed to the positive trend.
Depreciation and amortization for the three months ended Sept. 30, 2004 was comparable to the same period in 2003. Depreciation and amortization for the nine months ended Sept. 30, 2004 was $0.9 million lower than the nine months ended Sept. 30, 2003 due to closure of the Annapolis office and the resulting asset disposals in 2003.
At Sept. 30, 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. TransAlta has filed a petition for relief from the refund obligation.
TransAlta's fixed price trading positions were as follows: | ||||
Electricity | Natural Gas | |||
Units (000s) | MWh | GJ | ||
Fixed price payor, notional amounts, Sept. 30, 2004 | 16,861.9 | 36,768.4 | ||
Fixed price payor, notional amounts, Dec. 31, 2003 | 13,872.6 | 45,638.6 | ||
Fixed price receiver, notional amounts, Sept. 30, 2004 | 17,884.5 | 32,752.9 | ||
Fixed price receiver, notional amounts, Dec. 31, 2003 | 13,061.8 | 67,738.3 | ||
Maximum term in months, Sept. 30, 2004 | 51 | 37 | ||
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 Sept. 30, 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:
3 months ended Sept. 30 | 9 months ended Sept. 30 | |||||||
Electricity (GWh) | 2004 | 2003 | 2004 | 2003 | ||||
Physical | 19,515 | 14,549 | 46,854 | 42,061 | ||||
Financial | 5,765 | 9,106 | 14,415 | 26,031 | ||||
25,280 | 23,655 | 61,269 | 68,092 | |||||
3 months ended Sept. 30 | 9 months ended Sept. 30 | |||||||
Gas (million GJ) | 2004 | 2003 | 2004 | 2003 | ||||
Physical | 39.3 | 25.7 | 88.9 | 75.0 | ||||
Financial | 91.5 | 44.4 | 224.7 | 89.4 | ||||
130.8 | 70.1 | 313.6 | 164.4 | |||||
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Total electricity volumes in the three months ended Sept. 30, 2004 are slightly above, but consistent with, the same period in 2003. For the nine months ended Sept. 30, 2004, electricity volumes were lower than the same period in 2003 due to the elimination of trading in New York TCCs in 2003. 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.
The increase in gas volumes for both the three and nine month periods ending Sept. 30, 2004 relates to the increased use of heat rate contracts, which involve a gas component, to manage power price risk in electricity trading. Due to the liquidity of the gas market relative to power markets, the gas component in the heat rate contracts is actively traded to optimize the contracts. Gas trading, independent of power trading strategies, continues to be a small part of the risk taken in the marketplace.
The corporation's electrical transmission contracts net trading position of 5.0 million MWh at Sept. 30, 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 Sept. 30, 2004 TransAlta recorded a prepaid asset of $2.2 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.
In June 2003, FERC issued two show cause orders, the Partnership Gaming Order and the Gaming Practices Order, in which TransAlta's U.S. subsidiaries were named. These orders required TransAlta to justify certain trading activities in California between Jan. 1, 2000 and June 20, 2001. In response to FERC's show cause orders, TransAlta confirmed that it did not engage in gaming behavior. Based on the information provided by TransAlta, FERC Trial Staff filed a Motion to Dismiss with respect to TransAlta in the two show cause proceedings. On Jan. 22, 2004, FERC granted the Trial Staff's motion to dismiss TransAlta from both the Partnership Gaming Order and the Gaming Practices Order. FERC found that TransAlta did not engage in prohibited gaming practices.
Beginning in June 2002, a TransAlta U.S. subsidiary received requests from the U.S. Commodity Futures Trading Commission (CFTC) requesting information concerning the electricity and natural gas trading activities relating to the wash sales under the Commodity Exchange Act. TransAlta provided the CFTC with information pursuant to its request. On Jan. 29, 2004, TransAlta received official notice from the CFTC that it was closing its investigation at that time. While the CFTC reserved its right to re-open the investigation, TransAlta believes this is unlikely.
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, mark-to-market 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 FASB 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:
Sept. 30, | Dec. 31, | |||||
Balance Sheet | 2004 | 2003 | ||||
Price risk management assets | ||||||
Current | $ | 32.3 | $ | 68.4 | ||
Long-term | 36.9 | 31.6 | ||||
Price risk management liabilities | ||||||
Current | (26.4) | (64.3) | ||||
Long-term | (32.2) | (29.9) | ||||
Net price risk management assets outstanding | $ | 10.6 | $ | 5.8 | ||
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Net price risk management assets outstanding at Dec. 31, 2003 | $ | 5.8 | |
New contracts entered into during the period | 6.9 | ||
Contracts realized, amortized or settled during the period | (5.5) | ||
Changes in values attributable to market price and other market changes | (1.5) | ||
Changes in values attributable to discontinued hedge treatment of certain contracts | 4.9 | ||
Net price risk management assets outstanding at Sept. 30, 2004 | $ | 10.6 | |
The net price risk management assets and liabilities increased by $4.8 million compared to Dec. 31, 2003 primarily due to a $4.9 million price risk management asset resulting from discontinuance of hedge accounting related to a long-term power contract. The remaining decrease of $0.1 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 as unrealized gains as a component within gross margin of both Energy Marketing and Generation business segments.
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 | |||||||||||||||||||||
2004 | 2005 | 2006 | 2007 | 2008 | thereafter |
Total
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 with 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 , O T H E R E X P E N S E , F O R E I G N E X C H A N G E A N D N O N - C O N T R O L L I N G I N T E R E S T S
3 months ended Sept. 30 | 9 months ended Sept. 30 | ||||||||||||
2004 | 2003 | 2004 | 2003 | ||||||||||
Interest on recourse and non-recourse debt | $ | 51.3 | $ | 56.6 | $ | 162.2 | $ | 174.8 | |||||
Interest on preferred securities | 9.2 | 9.2 | 27.6 | 27.6 | |||||||||
Interest income | (0.8) | (0.6) | (1.7) | (3.1) | |||||||||
Capitalized interest | (5.5) | (8.4) | (15.3) | (40.6) | |||||||||
Net interest expense | 54.2 | 56.8 | 172.8 | 158.7 | |||||||||
Other expense | - | 2.2 | - | 2.2 | |||||||||
Foreign exchange loss (gain) | 1.7 | (1.0) | 2.4 | 6.7 | |||||||||
Non-controlling interests | 12.3 | 7.2 | 31.3 | 19.8 | |||||||||
Total | $ | 68.2 | $ | 65.2 | $ | 206.5 | $ | 187.4 | |||||
Net interest expense in the third quarter of 2004 was $2.6 million lower than the same period in 2003 due to decreased debt levels and decreased interest rates, partially offset by decreased capitalized interest. 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. In the first nine months of 2004, net interest expense increased by $14.1 million compared to the same period in 2003 due to decreased capitalized interest.
The foreign exchange loss in the first nine months of 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.
The increase in earnings attributable to non-controlling interests in the three and nine months ended Sept. 30, 2004 compared to the same periods in 2003 is the result of the sale of the Sheerness plant to TA Cogen in the third quarter of 2003.
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I N C O M E T A X E S
3 months ended Sept. 30 | 9 months ended Sept. 30 | ||||||||
2004 | 2003 | 2004 | 2003 | ||||||
Income tax expense | $ | 11.7 | $ | 26.6 | $ | 23.8 | $ | 55.1 | |
Effective tax rate | 24.6% | 18.3% | 19.4% | 22.4% |
The effective income tax rate in the third quarter of 2004 expressed as a percentage of earnings from continuing operations before income taxes, was higher compared to the same period in 2003. The effective tax rate for the three months ended Sept. 30, 2004 is higher than the same period in 2003 due to the impact of the gain on the sale of the Sheerness plant ($45.7 million), which was partially offset by the tax effect of the asset impairment charges ($29.3 million). The effective income tax rate for the first nine months of 2004 is lower than the same period in 2003 due to the New Zealand income tax recovery received in the second quarter of 2004 as previously discussed in Significant Events as well the reasons discussed above. As a result, in the three and nine months ended Sept. 30, 2004 income tax expense decreased by $14.9 million and $31.3 million, respectively, compared to the same periods in 2003.
F I N A N C I A L P O S I T I O N
The following chart outlines significant changes in the consolidated balance sheet from Dec. 31, 2003 to Sept. 30, 2004:
Increase/ | ||
(Decrease) | Explanation | |
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, net of | ||
accumulated depreciation | (114.3) | Increase due to the construction of the Summerview Wind Farm and |
Genesee 3 project and capitalized maintenance, partially offset by | ||
depreciation. | ||
Intangible assets | (28.5) | Amortization of the CE Gen sales contracts. |
Future income tax assets | ||
(including current portion) | 16.1 | Increased in unused tax losses that are expected to be recovered in |
future years. | ||
Other assets | 37.7 | Increase in mark-to-market valuation of cross-currency swaps. |
Short-term debt | (72.9) | Repayment of short-term debt. |
Accounts payable and accrued liabilities | (47.9) | Decreased capital expenditures. |
Long-term debt (including current portion) | (229.1) | Repayment of long-term debt. |
Non-recourse long-term debt | ||
(including current portion) | 35.7 | Increase due to Campeche debt becoming non-recourse offset by |
repayment of CE Gen secured bonds with Zinc Recovery funds. | ||
Future income tax liabilities | ||
(including current portion) | (18.2) | Decrease is due the finalization of the sale of the D&R operations, |
partially offset by an increase due to the acquisition of CE Gen. | ||
Non-controlling interests | 58.5 | Increase in non-controlling interest due to the Sheerness transaction. |
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S T A T E M E N T S O F C A S H F L O W S :
3 months ended Sept. 30 | 2004 | 2003 | Explanation | ||
Cash and cash equivalents, | |||||
beginning of period | $ 137.1 | $ 198.7 | |||
Provided by (used in): | |||||
Operating activities | 190.6 | 138.1 | In 2004, improved working capital position offset by slightly lower earnings. In 2003, | ||
increased cash earnings. | |||||
Investing activities | (66.8) | 65.5 | In 2004, capital expenditures of $79.7 million relating primarily to the construction of the | ||
Summerview Wind Farm, the Genesee 3 project and major maintenance. | |||||
In 2003, capital expenditures of $99.1 million relating primarily to the acquisition of | |||||
Genesee 3, and completion of construction activities at the Mexican plants more than | |||||
offset by the $149.9 million received from the sale of the Sheerness plant. | |||||
Financing activities | (99.6) | (299.5) | In 2004, net repayment of short- and long-term debt of $57.3 million, dividends on common | ||
shares of $32.6 million, and minority interest distributions of $31.9 million. | |||||
In 2003, net repayment of short- and long-term debt of $217.7 million, dividends on common | |||||
shares of $64.2 million, and minority interest distributions of $13.7 million. | |||||
Translation of foreign currency | |||||
cash | - | 12.5 | |||
Cash and cash equivalents, | |||||
end of period | $ 161.3 | $ 115.3 | |||
9 months ended Sept. 30 | 2004 | 2003 | Explanation | ||
Cash and cash equivalents, | |||||
beginning of period | $ 155.0 | $ 143.3 | |||
Provided by (used in): | |||||
Operating activities | 454.8 | 564.6 | In 2004, payments of tax installments, insurance premiums and unrealized gains on the | ||
valuation of trading activities. | |||||
In 2003, increased cash earnings and collection of commodity tax receivables (US$79.0 | |||||
million) as well as decreased receivables. | |||||
Investing activities | (93.3) | (529.1) | In 2004, capital expenditures of $262.1 million related to the construction of Genesee 3, the | ||
Summerview Wind Farm and major maintenance, partially offset by proceeds from the | |||||
exercise of TransAlta Power warrants ($63.9 million) and the collection of the $90.8 million | |||||
Zinc Recovery long-term receivable. | |||||
In 2003, capital expenditures of $505.0 million related to the acquisition of Genesee 3 and | |||||
construction activities in Mexico, the acquisition of CE Gen for $323.4 million, partially | |||||
offset by proceeds on the sale of the Goldfields gas pipeline ($21.6 million), proceeds from | |||||
the sale of the office building and the sale of the Sheerness plant ($215.7 million), and | |||||
recovery of CE Gen's restricted cash of $38.2 million. | |||||
Financing activities | (355.2) | (57.2) | In 2004, net repayment of short- and long-term debt ($220.0 million), dividends on common | ||
shares ($102.6 million), and minority interest distribution ($33.5 million). | |||||
In 2003, net repayment of short- and long-term debt of $169.1 million, cash dividends on | |||||
common shares of $122.6 million, and minority interest distributions of $26.5 million, | |||||
partially offset by net proceeds on the issuance of common shares of $265.0 million. | |||||
Translation of foreign currency | |||||
cash | -- | (6.3) | |||
Cash and cash equivalents, | |||||
end of period | $ 161.3 | $ | 115.3 |
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L I Q U I D I T Y A N D C A P I T A L R E S O U R C E S
In the three and nine months ended Sept. 30, 2004, TransAlta spent $79.7 million and $262.1 million, respectively, on capital expenditures. In the three and nine months ended Sept. 30, 2003 TransAlta spent $99.1 million and $505.0 million, respectively, on capital expenditures and acquisitions.
In the three months ended Sept. 30, 2004, TransAlta had overall net repayments (including short- and long-term debt) of $57.3 million compared to $217.7 million net repayment in the same period in 2003. In the nine months ended Sept. 30, 2004, TransAlta had an overall net repayment of debt (including short- and long-term debt) of $220.0 million compared to $169.1 million net borrowings in the same period in 2003. Including the non-recourse debt held by CE Gen, TransAlta's short- and long-term debt balance on Sept. 30, 2004 decreased by $266.3 million compared to Dec. 31, 2003. Cash flow from operations, the receipt of the Zinc Recovery receivable and the sale of TransAlta Power units associated with the related exercise of warrants by unit holders were used to repay debt. Warrants relating to the Sheerness sale, which entitled holders to the purchase of a TransAlta Power unit, expired on August 3, 2004. In the third quarter of 2004, 290,500 TransAlta Power units were sold by TransAlta for proceeds of $2.6 million. In addition, TransAlta Power issued 795,033 units under its Dividend Reinvestment Program. As TransAlta does not participate in this program a $0.7 million dilution gain was recorded.
At Sept. 30, 2004, TransAlta's total debt (including non-recourse debt) to invested capital ratio was 44.9 per cent (38.9 per cent excluding non-recourse debt). This represents an improvement from the Dec. 31, 2003 ratio of 47.6 per cent (42.5 per cent excluding non-recourse debt). On June 30, 2004, TransAlta extended its existing committed $1.5 billion syndicated bank loan facility. Debt to invested capital is defined on page 38 of this quarterly report.
At Sept. 30, 2004, TransAlta's working capital ratio was 104.6 per cent compared to 93.6 per cent at Dec. 31, 2003.
In July 2004, the corporation renewed its US $1.0 billion shelf registration.
TransAlta has provided guarantees of obligations of certain subsidiaries to counterparties to facilitate physical and financial transactions in various derivatives. To the extent liabilities for trading activities exist related to these guarantees, they are included in the consolidated balance sheet. To the extent liabilities exist for hedging activities, they are not recognized on the consolidated balance sheet. The aggregate amount of these guarantees at Sept. 30, 2004 for trading and hedging activities was $2.0 billion. In addition, the corporation has a number of unlimited guarantees. The exposure for trading and hedging activities at Sept. 30, 2004 under both the limited and unlimited guarantees was $473.9 million compared to $381.3 million at Dec. 31, 2003.
TransAlta has also provided guarantees to counterparties to support performance and payment of obligations of certain subsidiaries. To the extent obligations exist under the performance guarantees at Sept. 30, 2004, they are included in accounts payable and accrued liabilities. The aggregate of these guarantees at Sept. 30, 2004 was $864.5 million compared to $828.6 million at Dec. 31, 2003.
The corporation has approximately $1.3 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.
On Sept. 30, 2004, the corporation had approximately 193.0 million common shares outstanding in the amount of $1,594.4 million.
O U T L O O K
The key factors affecting the financial results for the remainder of 2004 continue to be 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.
:P17
T R A N S A L T A C O R P O R A T I O N
Q U A R T E R L Y R E P O R T 2 0 0 4
Production and availability
Generating capacity is expected to increase during the remainder of 2004 due to the completion of the 68 MW Summerview Wind Farm project. On Dec. 31, 2004 TransAlta expects to decommission units one and two of the Wabamun plant (62 MW and 57 MW, respectively).
Availability and production for the remainder of 2004 are expected to be higher than the first nine months of 2004 due to reduced planned maintenance. TransAlta expects to lose approximately 2,500 GWh of production due to planned maintenance in 2004, of which 1,966 GWh were lost in the first nine months. In 2003, TransAlta lost approximately 2,200 GWh as a result of planned maintenance, of which 1,863 GWh were lost in the first nine months.
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 following 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.
Power prices
Electricity spot prices for the remainder of the year are expected to be comparable to or higher than in the third quarter of 2004 in all markets due to increased volatility in the gas market and seasonal weather patterns. Spark spreads for the fourth quarter are expected to be comparable to or slightly higher than in the third quarter of 2004 as natural gas prices are also expected to average around their current levels.
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 the remainder of 2004, approximately 80 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 revenues from these contracts.
On June 15, 2004, the Ontario Ministry of Energy introduced Bill 100 in the legislature 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. Subject to passage of the legislation, implementation of the structure is targeted for early 2005. The future operating results of TransAlta's Sarnia Cogeneration plant may be significantly affected dependent on the legislation being passed and the resultant changes in merchant pricing and the availability of stable long-term contracts for electricity producers. At this time, TransAlta can not reasonably assess the impact of the proposed changes to the structure of the Ontario energy sector and its impact on Sarnia's future operational results.
Costs of production
Fluctuations in the cost of coal are minimized through ownership of reserves in Alberta and Washington. 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 the fourth quarter are expected to be comparable to the first three quarters of 2004.
Energy Marketing
Energy Marketing's trading activities are focused on real-time and short term forward markets. Real-time markets for the remainder of the year are expected to be consistent with the first nine months of 2004. Short-term forward markets show indications of increased volatility due to recent developments in the North American natural gas market. As it is expected that volatile gas prices will continue into the fourth quarter, we intend to reduce our risk profile and value at risk.
:P18
T R A N S A L T A C O R P O R A T I O N
Q U A R T E R L Y R E P O R T 2 0 0 4
Capital and maintenance expenditures
Capital expenditures for 2004 are expected to be approximately $360 million to $375 million of which approximately $130 million will be spent on renewable growth projects and the Genesee 3 project. The remainder will be spent on planned and preventative maintenance, including CE Gen, mine capital and productivity related investments. Financing for these expenditures is expected to come from a combination of cash from operations and the sale of TransAlta Power units.
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, offsetting foreign currency revenues. This strategy minimizes the impact on TransAlta of the recent appreciation in the Canadian dollar against the U.S. dollar.
Non-GAAP Measures
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 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 provides management with a measurement of operating performance which is readily comparable from period to period.
Gross margin less operating expenses and operating income are reconciled to net earnings below:
3 months ended Sept. 30 | 9 months ended Sept. 30 | |||||||||||
2004 | 2003 1 | 2004 | 2003 1 | |||||||||
Gross margin | $ | 366.3 | $ | 351.5 | $ | 1,063.6 | $ | 1,002.9 | ||||
Operating expenses | (253.7) | (248.1) | (736.1) | (676.8) | ||||||||
112.6 | 103.4 | 327.5 | 326.1 | |||||||||
Prior period regulatory decision | - | - | (22.9) | - | ||||||||
Gain on sale of TA Power units | 3.1 | - | 24.2 | - | ||||||||
Asset impairment charges | - | (84.7) | - | (84.7) | ||||||||
Gain on sale of Sheerness Generating Station | - | 191.5 | - | 191.5 | ||||||||
Operating income | 115.7 | 210.2 | 328.8 | 432.9 | ||||||||
Other income | - | (2.2 ) | - | (2.2) | ||||||||
Foreign exchange gain (loss) | (1.7) | 1.0 | (2.4) | (6.7) | ||||||||
Net interest expense | (54.2) | (56.8) | (172.8) | (158.7) | ||||||||
Earnings before non-controlling interests and income taxes | 59.8 | 152.2 | 153.6 | 265.3 | ||||||||
Non-controlling interests | 12.3 | 7.2 | 31.3 | 19.8 | ||||||||
Earnings before income taxes | 47.5 | 145.0 | 122.3 | 245.5 | ||||||||
Income tax expense | 11.7 | 26.6 | 23.8 | 55.1 | ||||||||
Earnings from continuing operations | 35.8 | 118.4 | 98.5 | 190.4 | ||||||||
Gain on disposal of discontinued operations, net of tax | - | - | 9.6 | - | ||||||||
Net earnings | $ | 35.8 | $ | 118.4 | $ | 108.1 | $ | 190.4 | ||||
1 | TransAlta early adopted the amended standard on the presentation of liabilities and equity on Jan. 1, 2004. See Note 1 to the unaudited interim consolidated financial statements for further discussion. Prior periods have been restated. |
:P19
T R A N S A L T A C O R P O R A T I O N
Q U A R T E R L Y R E P O R T 2 0 0 4
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: prior period regulatory decisions, gain on sale of TransAlta Power units, asset impairment charges, gain on sale of Sheerness Generating Station and earnings from discontinued operations, net of tax.
It is not appropriate to class the excluded items as one-time items as it is not possible to conclude, with certainty, that they, or similar items, will not reoccur within the next two years.
Earnings presented on a comparable basis from period to period is reconciled to net earnings below:
3 months ended Sept. 30 | 9 months ended Sept. 30 | |||||||||||||
2004 | 2003 1 | 2004 | 2003 1 | |||||||||||
Earnings on a comparable basis | $ 33.8 | $ 28.0 | 97.7 | $ 100.0 | ||||||||||
Prior period regulatory decision | - | - | (22.9) | - | ||||||||||
Gain on sale of TA Power units | 3.1 | - | 24.2 | - | ||||||||||
Asset impairment charges | - | (84.7) | - | (84.7) | ||||||||||
Gain on sale of Sheerness Generating Station | - | 191.5 | - | 191.5 | ||||||||||
Tax on above items | (1.1) | (16.4) | (0.5) | (16.4) | ||||||||||
Gain from discontinued operations, net of tax | - | - | 9.6 | - | ||||||||||
Net earnings | $ 35.8 | $ 118.4 | 108.1 | $ 190.4 | ||||||||||
Weighted average common shares outstanding in the period | 193.0 | 189.8 | 192.2 | 183.6 | ||||||||||
Earnings on a comparable basis per share | $ 0.17 | $ 0.15 | 0.51 | $ 0.55 | ||||||||||
1TransAlta early adopted the amended standard on the presentation of liabilities and equity on Jan. 1, 2004. See Note 1 to the unaudited interim consolidated financial statements for further discussion. Prior periods have been restated. | ||||||||||||||
S E L E C T E D Q U A R T E R L Y I N F O R M A T I O N | ||||||||||||||
(Unaudited, in millions of Canadian dollars except per share amounts) | ||||||||||||||
Q4 2003 | Q1 2004 | Q2 2004 | Q3 2004 | |||||||||||
Revenue | 661.5 | 712.7 | 670.1 | 743.0 | ||||||||||
Earnings from continuing operations | 43.8 | 47.2 | 15.5 | 35.8 | ||||||||||
Net earnings | 43.8 | 47.2 | 25.1 | 35.8 | ||||||||||
Basic earnings per common share: | ||||||||||||||
Continuing operations | 0.23 | 0.25 | 0.08 | 0.18 | ||||||||||
Net earnings | 0.23 | 0.25 | 0.13 | 0.18 | ||||||||||
Diluted earnings per common share: | ||||||||||||||
Continuing operations | 0.23 | 0.24 | 0.08 | 0.18 | ||||||||||
Net earnings | 0.23 | 0.24 | 0.13 | 0.18 | ||||||||||
Q4 2002 | Q1 2003 | Q2 2003 | Q3 2003 | |||||||||||
Revenue | 531.7 | 639.5 | 563.0 | 656.9 | ||||||||||
Earnings (loss) rom continuing operations | (62.0) | 48.7 | 23.3 | 118.4 | ||||||||||
Net earnings (loss) | (52.0) | 48.7 | 23.3 | 118.4 | ||||||||||
Basic earnings (loss) per common share: | ||||||||||||||
Continuing operations | (0.37) | 0.28 | 0.12 | 0.62 | ||||||||||
Net earnings (loss) | (0.31) | 0.28 | 0.12 | 0.62 | ||||||||||
Diluted earnings (loss) per common share: | ||||||||||||||
Continuing operations | (0.37) | 0.28 | 0.12 | 0.62 | ||||||||||
Net earnings (loss) | (0.31) | 0.28 | 0.12 | 0.62 | ||||||||||
:P20
T R A N S A L T A C O R P O R A T I O N
Q U A R T E R L Y R E P O R T 2 0 0 4
T R A N S A L T A C O R P O R A T I O N
C O N S O L I D A T E D S T A T E M E N T S O F E A R N I N G S A N D R E T A I N E D
E A R N I N G S
(in millions of Canadian dollars except per share amounts) | ||||||||||||
3 months ended Sept. 30 | 9 months ended Sept. 30 | |||||||||||
Unaudited | 2004 | 2003 | 2004 | 2003 | ||||||||
(Restated, | (Restated, | |||||||||||
Note 1) | Note 1) | |||||||||||
Revenues | $ | 743.0 | $ | 656.9 | $ | 2,125.8 | $ | 1,859.4 | ||||
Trading purchases | (59.9) | (26.9) | (140.4) | (72.2) | ||||||||
Fuel and purchased power | (316.8) | (278.5) | (921.8) | (784.3) | ||||||||
Gross margin | 366.3 | 351.5 | 1,063.6 | 1,002.9 | ||||||||
Operations, maintenance and administration | 154.3 | 153.2 | 434.5 | 412.7 | ||||||||
Depreciation and amortization(Note 11) | 93.8 | 89.1 | 283.9 | 246.6 | ||||||||
Taxes, other than income taxes | 5.6 | 5.8 | 17.7 | 17.5 | ||||||||
Operating expenses | 253.7 | 248.1 | 736.1 | 676.8 | ||||||||
Prior period regulatory decision(Note 4) | - | - | 22.9 | - | ||||||||
Gain on sale of TransAlta Power partnership units(Note 2) | (3.1) | - | (24.2) | - | ||||||||
Asset impairment charges(Note 12) | - | 84.7 | - | 84.7 | ||||||||
Gain on sale of Sheerness Generating Station(Note 2) | - | (191.5) | - | (191.5) | ||||||||
(3.1) | (106.8) | (1.3) | (106.8) | |||||||||
Operating income | 115.7 | 210.2 | 328.8 | 432.9 | ||||||||
Other expense | - | (2.2) | - | (2.2) | ||||||||
Foreign exchange gain (loss) | (1.7) | 1.0 | (2.4) | (6.7) | ||||||||
Net interest expense(Note 5) | (54.2) | (56.8) | (172.8) | (158.7) | ||||||||
Earnings before non-controlling interests and income taxes | 59.8 | 152.2 | 153.6 | 265.3 | ||||||||
Non-controlling interests | 12.3 | 7.2 | 31.3 | 19.8 | ||||||||
Earnings before income taxes | 47.5 | 145.0 | 122.3 | 245.5 | ||||||||
Income tax expense | 11.7 | 26.6 | 23.8 | 55.1 | ||||||||
Earnings from continuing operations | 35.8 | 118.4 | 98.5 | 190.4 | ||||||||
Gain on disposal of discontinued operations, net of tax(Note 2) | - | - | 9.6 | - | ||||||||
Net earnings | 35.8 | 118.4 | 108.1 | 190.4 | ||||||||
Common share dividends | (48.2) | (47.4) | (144.1) | (137.3) | ||||||||
Adjustment arising from normal course issuer bid(Note 8) | - | - | (1.1) | - | ||||||||
Retained earnings | ||||||||||||
Opening balance | 909.2 | 866.8 | 933.9 | 884.7 | ||||||||
Closing balance | $ | 896.8 | $ | 937.8 | $ | 896.8 | $ | 937.8 | ||||
Weighted average common shares outstanding in the period | 193.0 | 189.8 | 192.2 | 183.6 | ||||||||
Basic earnings per share | ||||||||||||
Earnings from continuing operations | $ | 0.18 | $ | 0.62 | $ | 0.51 | $ | 1.04 | ||||
Gain on disposal of discontinued operations, net of tax | - | - | 0.05 | - | ||||||||
Net earnings | $ | 0.18 | $ | 0.62 | $ | 0.56 | $ | 1.04 | ||||
Diluted earnings per share | ||||||||||||
Earnings from continuing operations | $ | 0.18 | $ | 0.62 | $ | 0.51 | $ | 1.04 | ||||
Gain on disposal of discontinued operations, net of tax | - | - | 0.05 | - | ||||||||
Net earnings | $ | 0.18 | $ | 0.62 | $ | 0.56 | $ | 1.04 | ||||
See accompanying notes. |
:P21
T R A N S A L T A C O R P O R A T I O N
Q U A R T E R L Y R E P O R T 2 0 0 4
T R A N S A L T A C O R P O R A T I O N
C O N S O L I D A T E D S T A T E M E N T S O F
C A S H F L O W S
(in millions of Canadian dollars) | ||||||||||||||
3 months ended Sept. 30 | 9 months ended Sept. 30 | |||||||||||||
Unaudited | 2004 | 2003 | 2004 | 2003 | ||||||||||
(Restated, | (Restated, | |||||||||||||
Note 1) | Note 1) | |||||||||||||
Operating activities | ||||||||||||||
Net earnings | $ | 35.8 | $ | 118.4 | $ | 108.1 | $ | 190.4 | ||||||
Depreciation and amortization(Note 11) | 101.9 | 100.8 | 309.1 | 271.2 | ||||||||||
California receivable provision(Note 4) | - | - | 22.9 | - | ||||||||||
Gain on sale of TransAlta Power partnership units(Note 2) | (3.1) | - | (24.2) | - | ||||||||||
Non-controlling interests | 12.3 | 7.2 | 31.3 | 19.8 | ||||||||||
Asset retirement obligation accretion(Note 6) | 5.1 | 5.2 | 15.4 | 17.3 | ||||||||||
Future income taxes | 9.4 | 21.2 | 26.6 | 23.0 | ||||||||||
Unrealized loss (gain) from energy marketing activities | 4.6 | (8.5) | (4.8) | (19.4) | ||||||||||
Asset retirement obligation costs settled | (10.1) | (19.1) | (16.7) | (22.6) | ||||||||||
Foreign exchange loss (gain) | 1.7 | (1.0) | 2.4 | 6.7 | ||||||||||
Asset impairment charge(Note 12) | - | 84.7 | - | 84.7 | ||||||||||
Loss (gain) on sale of assets | 1.2 | (189.0) | (10.9) | (189.4) | ||||||||||
Other non-cash items | 7.1 | (0.4) | 3.2 | 1.1 | ||||||||||
165.9 | 119.5 | 462.4 | 382.8 | |||||||||||
Change in non-cash operating working capital balances | 24.7 | 18.6 | (7.6) | 181.8 | ||||||||||
Cash flow from operating activities | 190.6 | 138.1 | 454.8 | 564.6 | ||||||||||
Investing activities | ||||||||||||||
Long-term receivables(Note 4) | - | (0.7) | 90.8 | - | ||||||||||
Additions to property, plant and equipment | (79.7) | (99.1) | (262.1) | (505.0) | ||||||||||
Proceeds on sale of property, plant and equipment | 0.7 | 149.9 | 12.7 | 215.7 | ||||||||||
Proceeds on sale of TransAlta Power partnership units | 2.6 | - | 61.7 | - | ||||||||||
Investments | - | - | - | 21.6 | ||||||||||
Restricted cash(Note 2) | 4.6 | (9.2) | 3.5 | 38.2 | ||||||||||
Acquisitions(Note 2) | - | - | - | (323.4) | ||||||||||
Deferred charges and other | 5.0 | 24.6 | 0.1 | 23.8 | ||||||||||
Cash flow from (used in) investing activities | (66.8) | 65.5 | (93.3) | (529.1) | ||||||||||
Financing activities | ||||||||||||||
Repayment of short-term debt | (35.4) | (208.3) | (72.9) | (188.3) | ||||||||||
Repayment of long-term debt | (21.9) | (9.4) | (149.8) | (129.9) | ||||||||||
Dividends on common shares | (32.6) | (64.2) | (102.6) | (122.6) | ||||||||||
Issuance of long-term debt | - | - | 2.7 | 149.1 | ||||||||||
Redemption of common shares | - | - | (1.5) | - | ||||||||||
Distributions to subsidiary's non-controlling limited partner | (12.9) | (13.7) | (33.5) | (26.5) | ||||||||||
Net proceeds on issuance of common shares(Note 8) | 2.4 | - | 2.4 | 265.0 | ||||||||||
Deferred financing charges and other | 0.8 | (3.9) | - | (4.0) | ||||||||||
Cash flow used in financing activities | (99.6) | (299.5) | (355.2) | (57.2) | ||||||||||
Cash flow from (used in) operating, investing and financing activities | 24.2 | (95.9) | 6.3 | (21.7) | ||||||||||
Effect of translation on foreign currency cash | - | 12.5 | - | (6.3) | ||||||||||
Increase (decrease) in cash and cash equivalents | 24.2 | (83.4) | 6.3 | (28.0) | ||||||||||
Cash and cash equivalents, beginning of period | 137.1 | 198.7 | 155.0 | 143.3 | ||||||||||
Cash and cash equivalents, end of period | $ | 161.3 | $ | 115.3 | $ | 161.3 | $ | 115.3 | ||||||
See accompanying notes. |
:P22
T R A NS A L T A CO R P O R A T I O N
Q U A R TE RL Y R E P O R T 2 0 0 4
T R A N S A L T A C O R P O R A T I O N
C O N S O L I D A T E D BA L A N C E SH E E T S
(in millions of Canadian dollars) | |||||||||
Sept. 30, | Dec. 31, | ||||||||
Unaudited | 2004 | 2003 * | |||||||
(Restated, | |||||||||
Note 1) | |||||||||
ASSETS | |||||||||
Current assets | |||||||||
Cash and cash equivalents | $ | 161.3 | $ | 155.0 | |||||
Accounts receivable | 402.4 | 420.1 | |||||||
Prepaid expenses | 64.7 | 53.8 | |||||||
Price risk management assets(Note 3) | 32.3 | 68.4 | |||||||
Future income tax assets | 40.1 | 29.4 | |||||||
Income taxes receivable | 77.8 | 108.9 | |||||||
Inventory | 46.3 | 47.0 | |||||||
824.9 | 882.6 | ||||||||
Restricted cash(Note 2) | 6.5 | 9.9 | |||||||
Investments | 5.0 | 5.0 | |||||||
Long-term receivables | (Note 4) | - | 120.1 | ||||||
Property, plant and equipment | |||||||||
Cost | 8,818.8 | 8,693.2 | |||||||
Accumulated depreciation | (2,547.6) | (2,307.7) | |||||||
6,271.2 | 6,385.5 | ||||||||
Goodwill(Note 2) | 145.7 | 149.6 | |||||||
Intangible assets | 448.7 | 477.2 | |||||||
Future income tax assets | 106.4 | 101.0 | |||||||
Price risk management assets(Note 3) | 36.9 | 31.6 | |||||||
Other assets | 275.4 | 237.7 | |||||||
Total assets | $ | 8,120.7 | $ | 8,400.2 | |||||
LIABILITIES AND SHAREHOLDERS’EQUITY | |||||||||
Current liabilities | |||||||||
Short-term debt | $ | 46.9 | $ | 119.8 | |||||
Accounts payable and accrued liabilities | 507.4 | 555.3 | |||||||
Price risk management liabilities(Note 3) | 26.4 | 64.3 | |||||||
Income taxes payable | 0.8 | - | |||||||
Future income tax liabilities | - | 4.6 | |||||||
Dividends payable | 19.1 | 14.9 | |||||||
Current portion of long-term debt - recourse | 130.4 | 138.5 | |||||||
Current portion of long-term debt - non-recourse | 57.8 | 45.3 | |||||||
788.8 | 942.7 | ||||||||
Long-term debt - recourse | 2,207.1 | 2,428.1 | |||||||
Long-term debt - non-recourse | 557.4 | 534.2 | |||||||
Preferred securities | (Notes 1 and 5) | 475.0 | 475.0 | ||||||
Deferred credits and other long-term liabilities(Note 6) | 380.5 | 365.1 | |||||||
Future income tax liabilities | 673.1 | 686.7 | |||||||
Price risk management liabilities(Note 3) | 32.2 | 29.9 | |||||||
Non-controlling interests | 536.4 | 477.9 | |||||||
Common shareholders' equity | |||||||||
Common shares(Note 8) | 1,594.4 | 1,555.7 | |||||||
Retained earnings | 896.8 | 933.9 | |||||||
Cumulative translation adjustment | (21.0) | (29.0) | |||||||
2,470.2 | 2,460.6 | ||||||||
Total liabilities and shareholders’ equity | $ | 8,120.7 | $ | 8,400.2 | |||||
Contingencies(Note 9) | |||||||||
See accompanying notes. | |||||||||
* Derived from the audited Dec. 31, 2003 consolidated financial statements. |
:P23
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N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S
(Unaudited)
(Tabular amounts in millions of Canadian dollars, except as otherwise noted)
1 . A C C O U N T I N G P O L I C I E S
These unaudited interim consolidated financial statements do not include all of the disclosures included in the corporation's annual consolidated financial statements. Accordingly, these unaudited interim consolidated financial statements should be read in conjunction with the corporation's most recent annual consolidated financial statements.
These unaudited interim financial statements reflect all adjustments (consisting of normal recurring adjustments and accruals) that are, in the opinion of management, necessary for a fair presentation of the results for the interim period.
TransAlta's results are seasonal due to the nature of the electricity market and related fuel costs.
The accounting policies used in the preparation of these unaudited interim consolidated financial statements conform with those used in the corporation's most recent annual consolidated financial statements, except for accounting for coal rights, preferred securities, and employee share purchase loans.
Presentation of coal rights
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. Generally Accepted Accounting Principles (GAAP) as tangible assets. Prior period amounts have been reclassified from intangible assets to tangible assets. There was no effect on net earnings as a result of the reclassification.
Accounting for preferred securities
TransAlta early adopted the amended Canadian Institute of Chartered Accountants (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 5)and therefore included as a deduction in arriving at net earnings. This change in accounting policy was recorded retroactively with restatement.
Employee share purchase loans
Effective Jan. 1, 2004, TransAlta has elected to prospectively present employee share purchase plan loans as a deduction from shareholders' equity. The impact of this new accounting treatment is immaterial to the consolidated financial statements.
Stock-based compensation
Effective Jan. 1, 2003, the corporation elected to prospectively use the fair value method of accounting for awards granted under its fixed stock option plans and its performance stock option plan subsequent to Jan. 1, 2003. No awards were granted in 2003 or the first nine months of 2004.
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Previously, the intrinsic value method was used. The following table provides pro forma measures of net earnings and earnings per share had compensation expense been recognized for awards granted prior to 2003 based on the estimated fair value of the options on the grant date in accordance with the fair value method of accounting for stock-based compensation:
3 months ended Sept. 30 | 9 months ended Sept. 30 | |||||||||||
2004 | 2003 | 2004 | 2003 | |||||||||
Reported net earnings | $ | 35.8 | $ | 118.4 | $ | 108.1 | $ | 190.4 | ||||
Compensation expense | 0.4 | 0.6 | 1.3 | 1.9 | ||||||||
Pro forma net earnings | $ | 35.4 | $ | 117.8 | $ | 106.8 | $ | 188.5 | ||||
Reported basic earnings per share | $ | 0.18 | $ | 0.62 | $ | 0.56 | $ | 1.04 | ||||
Compensation expense per share | - | - | 0.01 | 0.01 | ||||||||
Pro forma basic earnings per share | $ | 0.18 | $ | 0.62 | $ | 0.55 | $ | 1.03 | ||||
Reported diluted earnings per share | $ | 0.18 | $ | 0.62 | $ | 0.56 | $ | 1.04 | ||||
Compensation expense per share | - | - | 0.01 | 0.01 | ||||||||
Pro forma diluted earnings per share | $ | 0.18 | $ | 0.62 | $ | 0.55 | $ | 1.03 | ||||
2 . A C Q U I S I T I O N S A N D D I S P O S A L S
A. Acquisitions
On Jan. 29, 2003, the corporation acquired a 50 per cent interest in CE Generation LLC (CE Gen). The purchase price allocation was finalized in the second quarter of 2003 and is presented below:
Net assets acquired at assigned values: | |||
Working capital, including cash of $43.2 million | $ | 60.3 | |
Restricted cash | 57.9 | ||
Current income tax receivable | 2.4 | ||
Property, plant and equipment | 414.6 | ||
Intangible assets | 610.5 | ||
Goodwill | 108.9 | ||
Note receivable | 90.0 | ||
Non-recourse long-term debt, including current portion | (717.4) | ||
Future income tax liability | (216.0) | ||
Non-controlling interests | (44.6) | ||
Total | $ | 366.6 | |
Consideration: | |||
Cash | $ | 366.6 | |
Acquired intangibles in the amount of $610.5 million related to the fair value of power sale contracts acquired. The amount is being amortized on a straight-line basis over the terms of the contracts.
Goodwill resulted from the purchase of property, plant and equipment with no tax basis.
The amount of restricted cash acquired has been reduced subsequent to the acquisition as a result of TransAlta issuing a letter of credit in lieu of holding the restricted cash.
B. Disposals
On July 31, 2003, TransAlta completed the sale of its 50 per cent interest in the two-unit 756-MW coal-fired Sheerness plant to TransAlta Cogeneration, L.P. (TA Cogen) for $630.0 million. TransAlta received cash proceeds of $149.9 million, $315.0 million in TA Cogen units and $165.1 million in TransAlta Power L.P. (TransAlta Power) units. As part of the financing, and concurrent with the sale, TransAlta Power issued 17.75 million partnership units and 17.75 million warrants to the public for gross proceeds of $165.1 million, and 17.75 million partnership units to TransAlta for gross proceeds of $165.1 million. As a result of the unit issuance, TransAlta's ownership interest in TransAlta Power on July 31, 2003 was approximately 26 per cent. The warrants, when exercised, were exchangeable for one TransAlta Power unit at any time until Aug. 3, 2004. As the warrants were exercised, TransAlta sold TransAlta Power units back to TransAlta Power for $9.30 per unit, reducing its
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ownership interest in TransAlta Power to its original 0.01 per cent and increasing cash proceeds by a further $165.1 million assuming all warrants were exercised. As a result of exercising warrants and the subsequent sale of TransAlta Power units back to TransAlta Power, TransAlta's ownership interest in TransAlta Power was approximately 10 per cent at Sept. 30, 2004.
In the three and nine months ended Sept. 30, 2004, TransAlta recognized $3.1 million and $24.2 million, respectively, of dilution gains on the exercise of warrants. Prior to Aug. 3, 2004, 10.4 million warrants were exercised.
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.
3 . P R I C E R I S K M A N A G E M E N T A S S E T S A N D L I A B I L I T I E S
Energy Marketing'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 mark-to-market 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 physical transmission contracts are accounted for on an accrual basis in accordance with FASB EITF 02-03.
The following table illustrates movements in the fair value of the corporation's price risk management assets during the nine months ended Sept. 30, 2004:
Net price risk management assets outstanding at Dec. 31, 2003 | $ | 5.8 | |
New contracts entered into during the period | 6.9 | ||
Contracts realized, amortized or settled during the period | (5.5) | ||
Changes in values attributable to market price and other market changes | (1.5) | ||
Changes in values attributable to discontinued hedge treatment of certain contracts | 4.9 | ||
Net price risk management assets outstanding at Sept. 30, 2004 | $ | 10.6 | |
The source of the valuations of the above contracts and maturities over each of the next five calendar years and thereafter are as follows:
2009 and | |||||||||||||||||||||
2004 | 2005 | 2006 | 2007 | 2008 | thereafter | Total | |||||||||||||||
Prices actively quoted | $ | 1.0 | $ | 5.5 | $ | 1.8 | $ | 1.1 | $ | 1.0 | $ | - | $ | 10.4 | |||||||
Prices based on models | 0.2 | - | - | - | - | - | 0.2 | ||||||||||||||
$ | 1.2 | $ | 5.5 | $ | 1.8 | $ | 1.1 | $ | 1.0 | $ | - | $ | 10.6 | ||||||||
The carrying and fair value of energy trading assets and liabilities included on the consolidated balance sheet are as follows:
Sept. 30, | Dec. 31, | |||||
Balance Sheet | 2004 | 2003 | ||||
Price risk management assets | ||||||
Current | $ | 32.3 | $ | 68.4 | ||
Long-term | 36.9 | 31.6 | ||||
Price risk management liabilities | ||||||
Current | (26.4) | (64.3) | ||||
Long-term | (32.2) | (29.9) | ||||
Net price risk management assets outstanding | $ | 10.6 | $ | 5.8 | ||
In accordance with EITF 02-03, physical transmission is accounted for under accrual accounting. As of Sept. 30, 2004, TransAlta had recorded $2.2 million on the consolidated balance sheet as prepaid transmission related to these contracts. The maximum term of these contracts is 12 months.
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The corporation's trading positions at Sept. 30, 2004 were as follows:
Electricity | Natural Gas | |||
Units (000s) | MWh | GJ | ||
Fixed price payor, notional amounts, Sept. 30, 2004 | 16,861.9 | 36,768.4 | ||
Fixed price payor, notional amounts, Dec. 31, 2003 | 13,872.6 | 45,638.6 | ||
Fixed price receiver, notional amounts, Sept. 30, 2004 | 17,884.5 | 32,752.9 | ||
Fixed price receiver, notional amounts, Dec. 31, 2003 | 13,061.8 | 67,738.3 | ||
Maximum term in months, Sept. 30, 2004 | 51 | 37 | ||
Maximum term in months, Dec. 31, 2003 | 33 | 24 | ||
. |
The corporation's electrical transmission contracts trading position was 5.0 million megawatt hours (MWh) at Sept. 30, 2004 compared to 7.4 million MWh at Dec. 31, 2003.
4 . L O N G - T E R M R E C E I V A B L E S
During the first quarter of 2004, CE Gen collected amounts advanced to the Zinc Recovery Project which is owned by MidAmerican affiliates. TransAlta's portion of the proceeds was $90.8 million. Funds collected were used to repay a portion of the CE Gen secured bonds included in long-term debt.
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 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 additio nal pre-tax provision of US$17.2 million (Cdn$22.9 million). The after-tax impact was Cdn$14.9 million.
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 filing with FERC designed to address potential relief from all or a portion of the refund liability. 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 are recorded when the effect of such decisions are known, without adjustment to the financial statements of prior periods.
5 . L O N G - T E R M D E B T A N D I N T E R E S T E X P E N S E
TransAlta has included the corporation's preferred securities in long-term debt on the consolidated balance sheets(Note 1). Preferred securities distributions are included in interest expense as shown below:
3 months ended Sept. 30 | 9 months ended Sept. 30 | |||||||||||
2004 | 2003 | 2004 | 2003 | |||||||||
Interest on recourse and non-recourse debt | $ | 51.3 | $ | 56.6 | $ | 162.2 | $ | 174.8 | ||||
Interest on preferred securities | 9.2 | 9.2 | 27.6 | 27.6 | ||||||||
Interest income | (0.8) | (0.6) | (1.7) | (3.1) | ||||||||
Capitalized interest | (5.5) | (8.4) | (15.3) | (40.6) | ||||||||
Net interest expense | $ | 54.2 | $ | 56.8 | $ | 172.8 | $ | 158.7 | ||||
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The corporation has a US$133.6 million loan related to the financing of the gas-fired power plant in Campeche, Mexico which began commercial operations in May 2003. During construction and until certain conditions were met, the corporation provided a guarantee to the lenders of the plant(Note 10). On April 5, 2004, the plant was pledged as collateral and the corporation was relieved of its guarantee. At that time, the US$133.6 million of debt related to the plant became non-recourse to the corporation.
6 . A S S E T R E T I R E M E N T O B L I G A T I O N SA reconciliation between the opening and closing asset retirement obligation balances is provided below:
Balance, Dec. 31, 2003 | $ | 258.2 | ||
Liabilities incurred in period | 21.8 | |||
Liabilities settled in period | (16.7) | |||
Accretion expense | 15.4 | |||
Revisions in estimated cash flows | (1.0) | |||
Change in foreign exchange rates | (6.3) | |||
Balance, Sept. 30, 2004 | $ | 271.4 | ||
Liabilities incurred in the period reflect mining activities at the Alberta and Centralia coal mines. Asset retirement obligations are included in deferred credits and other long-term liabilities on the consolidated balance sheets.
7 . E M P L O Y E E F U T U R E B E N E F I T S
The corporation has registered pension plans in Canada and the U.S. covering substantially all employees of the corporation in these countries and specific named employees working internationally. These plans have defined benefit and defined contribution options and in Canada, there is an additional supplemental defined benefit plan for certain employees. The defined benefit option of the registered pension plans have been closed for new employees for all periods presented. Costs recognized in the period are presented below:
3 months ended Sept. 30, 2004 | Registered | Supplemental | Other | Total | ||||||||
Current service cost | $ | 1.1 | $ | 0.2 | $ | 0.3 | $ | 1.6 | ||||
Interest cost | 5.1 | 0.5 | 0.3 | 5.9 | ||||||||
Expected return on plan assets | (5.9) | - | - | (5.9) | ||||||||
Amortization of experience loss | 0.5 | 0.1 | 0.1 | 0.7 | ||||||||
Amortization of net transition obligation (asset) | (2.3) | - | - | (2.3) | ||||||||
Defined benefit expense (income) | (1.5) | 0.8 | 0.7 | - | ||||||||
Defined contribution option expense of registered pension plan | 2.4 | - | - | 2.4 | ||||||||
Net expense | $ | 0.9 | $ | 0.8 | $ | 0.7 | $ | 2.4 | ||||
3 months ended Sept. 30, 2003 | Registered | Supplemental | Other | Total | ||||||||
Current service cost | $ | 1.9 | $ | 0.7 | $ | 0.3 | $ | 2.9 | ||||
Interest cost | 10.5 | 1.1 | 0.5 | 12.1 | ||||||||
Expected return on plan assets | (11.8) | - | - | (11.8) | ||||||||
Amortization of experience loss | 0.7 | 0.3 | 0.2 | 1.2 | ||||||||
Amortization of past service cost | 0.1 | (0.1) | - | - | ||||||||
Amortization of net transition obligation (asset) | (4.5) | 0.1 | - | (4.4) | ||||||||
Defined benefit expense (income) | (3.1) | 2.1 | 1.0 | - | ||||||||
Defined contribution option expense of registered pension plan | 4.9 | - | - | 4.9 | ||||||||
Net expense | $ | 1.8 | $ | 2.1 | $ | 1.0 | $ | 4.9 | ||||
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9 months ended Sept. 30, 2004 | Registered | Supplemental | Other | Total | |||||||||||
Current service cost | $ | 3.2 |
$
9 months ended Sept. 30, 2003
8 . C O M M O N S H A R E S I S S U E D A N D O U T S T A N D I N G
TransAlta Corporation is authorized to issue an unlimited number of voting common shares without nominal or par value. At Sept. 30, 2004, the corporation had 193.0 million (Dec. 31, 2003 - 190.7 million) common shares issued and outstanding plus outstanding employee stock options to purchase an additional 3.0 million shares (Dec. 31, 2003 - 3.1 million).
In March 2003, the corporation issued 15.0 million common shares for gross proceeds of $240.0 million, with issue costs of $8.0 million. The offering included an option for the underwriters to purchase a further 2.25 million common shares for $36.0 million. This option was exercised on April 17, 2003 with issue costs of $3.0 million.
In February 2004, TransAlta announced a normal course issuer bid to repurchase up to 3.0 million common shares for cancellation. 143,500 shares were repurchased in the first nine months of 2004. The $1.1 million excess of the repurchase price over the average net book value was charged to retained earnings.
9 . C O N T I N G E N C I E S
In March 2003, FERC completed its investigation of natural gas and power markets and indicated that the total industry refunds for price overcharges will be higher than originally anticipated. In June 2003, FERC issued two show cause orders, the Partnership Gaming Order and the Gaming Practices Order, in which TransAlta's U.S. subsidiaries were named. These orders required TransAlta to justify certain trading activities in California between Oct. 1, 2000 and June 20, 2001. In response to FERC's show cause orders, TransAlta confirmed that it did not engage in gaming behavior. Based on the information provided by TransAlta, FERC Trial Staff filed a Motion to Dismiss with respect to TransAlta in the two show cause proceedings. On Jan. 22, 2004, FERC granted the FERC Trial Staff's motion to dismiss TransAlta from both the Partnership Gaming Order and the Gaming Practices Order. FERC found that TransAlta did not engage in prohibited gaming practices.
On May 30, 2002, the California Attorney General's Office filed civil complaints in the state court of California against eight wholesale power companies, including TransAlta. The complaint alleges violations of California's unfair business practices law in connection with rates charged for wholesale electricity sales. The state court denied the Attorney General's complaint and granted an order to dismiss the claims against TransAlta. The Attorney General has appealed this decision. The appeal was denied on Oct. 12, 2004 by the U.S. Court of Appeals for the Ninth Circuit.
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CE Gen's geothermal and cogeneration facilities are qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA) and their contracts for the sale of electricity are subject to regulations thereunder. In order to promote open competition in the industry, legislation has been proposed in the U.S. Congress that calls for either a repeal of PURPA on a prospective basis or the significant restructuring of the regulations governing the electric industry, including sections of PURPA. Current federal legislative proposals would not abrogate, amend, or modify existing contracts with electric utilities. The ultimate outcome of any proposed legislation is unknown at this time.
The corporation is involved in various other claims and legal actions arising from the normal course of business. The corporation does not expect that the outcome of these proceedings will have a materially adverse effect on the corporation.
10 . G U A R A N T E E S
TransAlta has provided guarantees of obligations of certain subsidiaries to counterparties to facilitate physical and financial transactions in various derivatives. To the extent liabilities for trading activities exist related to these guarantees, they are included in the consolidated balance sheet. To the extent liabilities exist for hedging activities, they are not recognized on the consolidated balance sheet. The aggregate of these guarantees at Sept. 30, 2004 for trading and hedging activities was $2.0 billion. In addition, the corporation has a number of unlimited guarantees. The exposure for trading and hedging activities at Sept. 30, 2004 under both the limited and unlimited guarantees was $473.9 million compared to $381.3 million at Dec. 31, 2003.
TransAlta has also provided guarantees to counterparties to support performance and payment of obligations of certain subsidiaries. To the extent obligations exist under the performance guarantees at Sept. 30, 2004, they are included in accounts payable and accrued liabilities. The aggregate of these guarantees at Sept. 30, 2004 was $864.5 million compared to $828.6 million at Dec. 31, 2003.
The corporation has approximately $1.3 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.
11 . S E G M E N T E D D I S C L O S U R E S
The results of CE Gen are included in the Generation segment from the date of purchase (Jan. 29, 2003).
Each business segment assumes responsibility for its operating results measured to operating income.
I. Earnings information | ||||||||||||
Energy | ||||||||||||
3 months ended Sept. 30, 2004 | Generation | Marketing | Corporate | Total | ||||||||
Revenues | $ | 669.2 | $ | 73.8 | $ | - | $ | 743.0 | ||||
Trading purchases | - | (59.9) | - | (59.9) | ||||||||
Fuel and purchased power | (316.8) | - | - | (316.8) | ||||||||
Gross margin | 352.4 | 13.9 | - | 366.3 | ||||||||
Operations, maintenance and administration | 139.8 | 1.6 | 12.9 | 154.3 | ||||||||
Depreciation and amortization | 90.3 | 0.6 | 2.9 | 93.8 | ||||||||
Taxes, other than income taxes | 5.6 | - | - | 5.6 | ||||||||
Operating expenses | 235.7 | 2.2 | 15.8 | 253.7 | ||||||||
Gain on sale of TransAlta Power partnership units | 3.1 | - | - | 3.1 | ||||||||
Operating income (loss) before corporate allocations | 119.8 | 11.7 | (15.8) | 115.7 | ||||||||
Corporate allocations | 14.1 | 1.7 | (15.8) | - | ||||||||
Operating income | $ | 105.7 | $ | 10.0 | $ | - | $ | 115.7 | ||||
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Energy | |||||||||||||
3 months ended Sept. 30, 2003 | Generation | Marketing | Corporate | Total | |||||||||
Revenues | $ | 613.6 | $ | 43.3 | $ | - | $ | 656.9 | |||||
Trading purchases | - | (26.9) | - | (26.9) | |||||||||
Fuel and purchased power | (278.5) | - | - | (278.5) | |||||||||
Gross margin | 335.1 | 16.4 | - | 351.5 | |||||||||
Operations, maintenance and administration | 134.8 | 4.7 | 13.7 | 153.2 | |||||||||
Depreciation and amortization | 85.7 | 0.8 | 2.6 | 89.1 | |||||||||
Taxes, other than income taxes | 5.8 | - | - | 5.8 | |||||||||
Operating expenses | 226.3 | 5.5 | 16.3 | 248.1 | |||||||||
Asset impairment charges | (84.7) | - | - | (84.7) | |||||||||
Gain on sale of Sheerness Generating Station | 191.5 | - | - | 191.5 | |||||||||
Operating income (loss) before corporate allocations | 215.6 | 10.9 | (16.3) | 210.2 | |||||||||
Corporate allocations | 14.5 | 1.8 | (16.3) | - | |||||||||
Operating income | $ | 201.1 | $ | 9.1 | $ | - | $ | 210.2 | |||||
Energy | |||||||||||||
9 months ended Sept. 30, 2004 | Generation | Marketing | Corporate | Total | |||||||||
Revenues | $ | 1,942.1 | $ | 183.7 | $ | - | $ | 2,125.8 | |||||
Trading purchases | - | (140.4) | - | (140.4) | |||||||||
Fuel and purchased power | (921.8) | - | - | (921.8) | |||||||||
Gross margin | 1,020.3 | 43.3 | - | 1,063.6 | |||||||||
Operations, maintenance and administration | 381.9 | 5.0 | 47.6 | 434.5 | |||||||||
Depreciation and amortization | 273.2 | 1.5 | 9.2 | 283.9 | |||||||||
Taxes, other than income taxes | 17.7 | - | - | 17.7 | |||||||||
Operating expenses | 672.8 | 6.5 | 56.8 | 736.1 | |||||||||
Prior period regulatory decision | - | (22.9) | - | (22.9) | |||||||||
Gain on sale of TransAlta Power partnership units | 24.2 | - | - | 24.2 | |||||||||
Operating income (loss) before corporate allocations | 371.7 | 13.9 | (56.8) | 328.8 | |||||||||
Corporate allocations | 50.5 | 6.3 | (56.8) | - | |||||||||
Operating income | $ | 321.2 | $ | 7.6 | $ | - | $ | 328.8 | |||||
Energy | |||||||||||||
9 months ended Sept. 30, 2003 | Generation | Marketing | Corporate | Total | |||||||||
Revenues | $ | 1,787.3 | $ | 72.1 | $ | - | $ | 1,859.4 | |||||
Trading purchases | - | (72.2) | - | (72.2) | |||||||||
Fuel and purchased power | (784.3) | - | - | (784.3) | |||||||||
Gross margin | 1,003.0 | (0.1) | - | 1,002.9 | |||||||||
Operations, maintenance and administration | 361.3 | 9.1 | 42.3 | 412.7 | |||||||||
Depreciation and amortization | 233.8 | 2.4 | 10.4 | 246.6 | |||||||||
Taxes, other than income taxes | 17.5 | - | - | 17.5 | |||||||||
Operating expenses | 612.6 | 11.5 | 52.7 | 676.8 | |||||||||
Asset impairment charges | (84.7) | - | - | (84.7) | |||||||||
Gain on sale of Sheerness Generating Station | 191.5 | - | - | 191.5 | |||||||||
Operating income (loss) before corporate allocations | 497.2 | (11.6) | (52.7) | 432.9 | |||||||||
Corporate allocations | 46.8 | 5.9 | (52.7) | - | |||||||||
Operating income (loss) | $ | 450.4 | $ | (17.5) | $ | - | $ | 432.9 | |||||
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II. Selected balance sheet information | |||||||||||||
Energy | |||||||||||||
Sept. 30, 2004 | Generation | Marketing | Corporate | Total | |||||||||
Goodwill | $ | 116.2 | $ | 29.5 | $ | - | $ | 145.7 | |||||
Total segment assets | $ | 7,314.6 | $ | 210.1 | $ | 596.0 | $ | 8,120.7 | |||||
Dec. 31, 2003 | |||||||||||||
Goodwill | $ | 120.3 | $ | 29.3 | $ | - | $ | 149.6 | |||||
Total segment assets | $ | 7,598.8 | $ | 238.9 | $ | 562.5 | $ | 8,400.2 | |||||
III. Selected cash flow information | |||||||||||||
Energy | |||||||||||||
3 months ended Sept. 30, 2004 | Generation | Marketing | Corporate | Total | |||||||||
Capital expenditures | $ | 77.5 | $ | 0.1 | $ | 2.1 | $ | 79.7 | |||||
3 months ended Sept. 30, 2003 | |||||||||||||
Capital expenditures | $ | 96.9 | $ | 0.1 | $ | 2.1 | $ | 99.1 | |||||
Energy | |||||||||||||
9 months ended Sept. 30, 2004 | Generation | Marketing | Corporate | Total | |||||||||
Capital expenditures | $ | 255.0 | $ | 0.5 | $ | 6.6 | $ | 262.1 | |||||
9 months ended Sept. 30, 2003 | |||||||||||||
Capital expenditures | $ | 498.3 | $ | 0.7 | $ | 6.0 | $ | 505.0 | |||||
Acquisitions | $ | 323.4 | $ | - | $ | - | $ | 323.4 | |||||
Depreciation and amortization expense per statement of cash flows: | |||||||||||||
3 months ended Sept. 30 | 9 months ended Sept. 30 | ||||||||||||
2004 | 2003 | 2004 | 2003 | ||||||||||
Depreciation and amortization expense for reportable segments | $ | 93.8 | $ | 89.1 | $ | 283.9 | $ | 246.6 | |||||
Mining equipment depreciation, included in fuel and purchased power | 16.5 | 25.1 | 40.4 | 38.6 | |||||||||
Accretion expense, included in depreciation and amortization expense | (5.1) | (5.2) | (15.4) | (17.3) | |||||||||
Other | (3.3) | (8.2) | 0.2 | 3.3 | |||||||||
$ | 101.9 | $ | 100.8 | $ | 309.1 | $ | 271.2 | ||||||
12 . A S S E T I M P A I R M E N T C H A R G E S
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 recovered. As a result, TransAlta has recorded a pre-tax $84.7 million impairment charge ($55.4 million after-tax) in the third quarter of 2003 to write down the turbines to fair value.
13 . C O M P A R A T I V E F I G U R E S
Certain comparative figures have been reclassified to conform to the current period's presentation.
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14 . U N I T E D S T A T E S G E N E R A L L Y A C C E P T E D A C C O U N T I N G
P R I N C I P L E S
These consolidated financial statements have been prepared in accordance with Canadian GAAP, which, in most respects, conform to U.S. GAAP. Significant differences between Canadian and U.S. GAAP are as follows:
A . E A R N I N G S A N D E A R N I N G S P E R S H A R E ( E P S )
3 months ended Sept. 30 | 9 months ended Sept. 30 | ||||||||||||
Reconciling items | 2004 | 2003 | 2004 | 2003 | |||||||||
Earnings from continuing operations - Canadian GAAP | $ | 35.8 | $ | 118.4 | $ | 98.5 | $ | 190.4 | |||||
Derivatives and hedging activities, net of tax | I | (0.4) | 0.7 | (2.4) | (3.4) | ||||||||
Start-up costs, net of tax | II | (0.1) | (3.2) | (0.1) | (4.6) | ||||||||
Amortization of debt extinguishment, net of tax | III | - | 10.7 | - | 11.1 | ||||||||
Amortization of pension transition adjustment | V | (1.2) | (1.4) | (3.5) | (4.3) | ||||||||
Earnings from continuing operations - U.S. GAAP | 34.1 | 125.2 | 92.5 | 189.2 | |||||||||
Net gain on disposal of discontinued operations - | |||||||||||||
Canadian and U.S. GAAP | - | - | 9.6 | - | |||||||||
Net earnings before change in accounting principle - U.S. GAAP | 34.1 | 125.2 | 102.1 | 189.2 | |||||||||
Cumulative effect of change in accounting principle, net of tax | X | - | - | - | 52.5 | ||||||||
Net earnings - U.S. GAAP | $ | 34.1 | $ | 125.2 | $ | 102.1 | $ | 241.7 | |||||
Foreign currency cumulative translation adjustment | I, VII | 0.2 | 27.4 | 23.8 | 16.4 | ||||||||
Net gain (loss) on derivative instruments | I,VII | 5.9 | 24.9 | (5.7) | (1.0) | ||||||||
Comprehensive income - U.S. GAAP | $ | 40.2 | $ | 177.5 | $ | 120.2 | $ | 257.1 | |||||
Basic EPS - U.S. GAAP | |||||||||||||
Earnings from continuing operations | $ | 0.18 | $ | 0.66 | $ | 0.48 | $ | 1.03 | |||||
Net gain on disposal of discontinued operations | - | - | 0.05 | - | |||||||||
Cumulative effect of change in accounting principle | - | - | - | 0.29 | |||||||||
Net earnings | $ | 0.18 | $ | 0.66 | $ | 0.53 | $ | 1.32 | |||||
Diluted EPS - U.S. GAAP | |||||||||||||
Earnings from continuing operations | $ | 0.18 | $ | 0.66 | $ | 0.48 | $ | 1.03 | |||||
Net gain on disposal of discontinued operations | - | - | 0.05 | - | |||||||||
Cumulative effect of change in accounting principle | - | - | - | 0.29 | |||||||||
Net earnings | $ | 0.18 | $ | 0.66 | $ | 0.53 | $ | 1.32 | |||||
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B . B A L A N C E S H E | E T | I N F O R M A T I O N | |||||||||||||
Sept. 30, 2004 | Dec. 31, 2003 | ||||||||||||||
Reconciling | Canadian | Canadian | |||||||||||||
items | GAAP | U.S. GAAP | GAAP | U.S. GAAP | |||||||||||
Assets | |||||||||||||||
Cash | IX, XII | $ | 161.3 | $ | 124.9 | $ | 155.0 | $ | 155.0 | ||||||
Current derivative assets | I | - | 34.1 | - | 6.9 | ||||||||||
Accounts receivable | VIII, XII | 402.4 | 407.5 | 420.1 | 409.3 | ||||||||||
Prepaid expenses | XII | 64.7 | 63.1 | 53.8 | 53.8 | ||||||||||
Income taxes receivable | I | 77.8 | 97.3 | 108.9 | 126.3 | ||||||||||
Investments | IX, XII | 5.0 | 404.0 | 5.0 | 189.4 | ||||||||||
Property, plant and equipment, net | II, XII | 6,271.2 | 5,702.4 | 6,385.5 | 6,382.6 | ||||||||||
Long-term derivative asset | I, XI | - | 171.4 | - | 102.8 | ||||||||||
Other assets | I, II, XII | 275.4 | 80.0 | 237.7 | 76.6 | ||||||||||
Liabilities | |||||||||||||||
Accounts payable and accrued liabilities | V, XII | 507.4 | 461.8 | 553.3 | 517.2 | ||||||||||
Income taxes payable | II | 0.8 | - | - | - | ||||||||||
Current derivative liabilities | I | - | 38.6 | - | 40.3 | ||||||||||
Current portion of long-term debt | IX, XII | 188.2 | 180.2 | 183.8 | 183.8 | ||||||||||
Long-term debt | I, XII | 2,764.5 | 2,656.5 | 2,962.3 | 3,185.9 | ||||||||||
Deferred credits and other long-term liabilities | I, XI, XII | 380.5 | 371.4 | 365.1 | 364.5 | ||||||||||
Long-term derivative liabilities | I | - | 42.3 | - | 12.2 | ||||||||||
Future or deferred income tax liabilities | I, II, IV, V | 673.1 | 663.1 | 686.7 | 671.8 | ||||||||||
Non-controlling interest | I | 536.4 | 534.8 | 477.9 | 475.6 | ||||||||||
Equity | |||||||||||||||
Common shares | VIII | 1,594.4 | 1,594.4 | 1,555.7 | 1,554.8 | ||||||||||
Retained earnings | I, II, V | 896.8 | 892.9 | 933.9 | 936.0 | ||||||||||
Cumulative translation adjustment | I | (21.0) | - | (29.0) | - | ||||||||||
Accumulated other comprehensive income | I, V | - | (88.0) | - | (106.1) | ||||||||||
C . R E C O N C I L I N G I T E M S
I. Derivatives and hedging activities(i) FAIR VALUE HEDGING STRATEGY
The corporation enters into forward exchange contracts to hedge certain firm commitments denominated in foreign currencies to protect against adverse changes in exchange rates and uses interest rate swaps to manage interest rate exposure. The swaps modify exposure to interest rate risk by converting a portion of the corporation's fixed-rate debt to a floating rate.The corporation's fair value hedges resulted in a net impact to income of $nil in the three and nine months ended Sept. 30, 2004 and 2003 related to the ineffective portion of its hedging instruments (inclusive of the time value of money) as well as the portion not designated as a hedge.
(ii) CASH FLOW HEDGING STRATEGY
In the three and nine months ended Sept. 30, 2004, the corporation's cash flow hedges resulted in an after-tax loss of $nil (2003 - $(0.1) million and $0.3 million respectively) related to the ineffective portion of its hedging instruments, and an after-tax effect of $nil (2003 - $nil) related to the portion not designated as a hedge.
In November 2003, forward starting swaps with a notional amount of US$200.0 million and treasury and spread locks with a notional amount of $100.0 million were settled and debt was issued, resulting in an after-tax loss of $25.3 million. The loss is being reclassified from accumulated other comprehensive income (AOCI) into income as interest expense is recognized on the debt.
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Over the next 12 months, the corporation estimates that $3.3 million of after-tax losses that arose from cash flow hedges will be reclassified from AOCI to net earnings. The corporation also estimates that $3.7 million of after-tax losses on cash flow hedging instruments that arose on adoption of Statement 133 will be reclassified from AOCI to earnings. These estimates assume constant gas and power prices, interest rates and exchange rates over time; however, the actual amounts that will be reclassified will vary based on changes in these factors. Therefore, management is unable to predict what the actual reclassification from AOCI to earnings (positive or negative) will be for the next 12 months.
(iii) NET INVESTMENT HEDGES
The company uses cross-currency interest rate swaps, forward sales contracts and direct foreign currency debt to hedge its exposure to changes in the carrying value of its investments in its foreign subsidiaries in the U.S., Australia and Mexico. Realized and unrealized gains and losses from these hedges are included in Other Comprehensive Income (OCI), with the related amounts due to or from counterparties included in long-term derivative assets and liabilities and long-term debt.
In the three and nine months ended Sept. 30, 2004, the corporation recognized an after-tax gain of $0.2 million and $23.8 million, respectively (2003 - $27.4 million and $16.4 million respectively) on its net investment hedges, included in OCI.
In the three and nine months ended Sept. 30, 2004, the corporation recognized after-tax gains of $nil (2003 - $nil), related to ineffectiveness of net investment hedges.
(iv) TRADING ACTIVITIES
The corporation markets energy derivatives to optimize returns from assets, to earn trading revenues and to gain market information. Derivatives, as defined under Statement 133, are recorded on the consolidated balance sheets at fair value under both Canadian and U.S. GAAP. Non-derivative contracts entered into subsequent to the rescission of EITF 98-10 are accounted for using the accrual method.
(v) OTHER HEDGING ACTIVITIES
In the three and nine months ended Sept. 30, 2004, the corporation recognized pre-tax losses of $0.2 million (2003 -$3.7 million gain and $0.3 million gain, respectively) related to hedging activities that do not qualify for hedge accounting under Statement 133.
II. Start-up costs
Under U.S. GAAP, certain start-up costs, including revenues and expenses in the pre-operating period, are expensed rather than capitalized to deferred charges and property, plant and equipment as under Canadian GAAP, which also results in decreased depreciation and amortization expense under U.S. GAAP.
III. Debt extinguishment
Under U.S. GAAP, the premium on redemption of long-term debt related to the 1998 limited partnership transaction was recorded when incurred, whereas for Canadian GAAP, the loss was being amortized to earnings over the period of the limited partnership (20 years). As the buyback option was terminated in connection with the sale of the Sheerness plant, the deferred amount was recognized in earnings in 2003.
IV. Income taxes
Future income taxes under Canadian GAAP are referred to as deferred income taxes under U.S. GAAP.
Deferred income taxes under U.S. GAAP would be as follows:
Sept. 30, | Dec. 31, | |||||
2004 | 2003 | |||||
Future income tax liabilities (net) under Canadian GAAP | $ | (526.6) | $ | (560.9) | ||
Derivatives | 24.1 | 31.3 | ||||
Start-up costs | (2.3) | (2.3) | ||||
Employee future benefits | (11.8) | (14.1) | ||||
$ | (516.6) | $ | (546.0) | |||
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Comprised of the following: | ||||||
Current deferred income tax assets | $ | 40.1 | $ | 29.4 | ||
Long-term deferred income tax assets | 106.4 | 101.0 | ||||
Current deferred income tax liabilities | - | (4.6) | ||||
Long-term deferred income tax liabilities | (663.1) | (671.8) | ||||
$ | (516.6) | $ | (546.0) | |||
V. Employee future benefits |
U.S. GAAP requires that the cost of employee pension benefits be determined using the accrual method with application from 1989. It was not feasible to apply this standard using this effective date. The transition asset as at Jan. 1, 1998 was determined in accordance with elected practice prescribed by the Securities and Exchange Commission (SEC) and is amortized over 10 years.
As a result of the corporation's plan asset return experience for its U.S. registered pension plan, at Dec. 31, 2003, the corporation was required under U.S. GAAP to recognize an additional minimum liability. The liability was recorded as a reduction in common equity through a charge to OCI and did not affect net income for 2003. The charge to OCI will be restored through common equity in future periods to the extent the fair value of trust assets exceeds the accumulated benefit obligation.
VI. Joint ventures
In accordance with Canadian GAAP, joint ventures are required to be proportionately consolidated regardless of the legal form of the entity. Under U.S. GAAP, incorporated joint ventures are required to be accounted for by the equity method. However, in accordance with practices prescribed by the SEC, the corporation, as a Foreign Private Issuer, has elected for the purpose of this reconciliation to account for incorporated joint ventures by the proportionate consolidation method.
VII. Other comprehensive income (loss) | ||||||||||||
The changes in the components of OCI were as follows: | ||||||||||||
3 months ended Sept. 30 | 9 months ended Sept. 30 | |||||||||||
2004 | 2003 | 2004 | 2003 | |||||||||
Net gain (loss) on derivative instruments: | ||||||||||||
Unrealized gain (loss) net of taxes of $7.8 million | $ | 5.0 | $ | 24.0 | $ | (8.4) | $ | (3.7) | ||||
Reclassification adjustment for gains included in net income, | ||||||||||||
net of taxes of $1.5 million | 0.9 | 0.9 | 2.7 | 2.7 | ||||||||
Net gain (loss) on derivative instruments | 5.9 | 24.9 | (5.7) | (1.0) | ||||||||
Translation adjustments | 0.2 | 27.4 | 23.8 | 16.4 | ||||||||
Other comprehensive income (loss) | $ | 6.1 | $ | 52.3 | $ | 18.1 | $ | 15.4 | ||||
The components of AOCI were: | ||||||||||||
Sept. 30, | Dec. 31, | |||||||||||
2004 | 2003 | |||||||||||
Net gain (loss) on derivative instruments | $ | (76.9) | $ | (71.2) | ||||||||
Translation adjustments | (10.0) | (33.8) | ||||||||||
Registered pension alternate minimum liabilities | (1.1) | (1.1) | ||||||||||
Accumulated other comprehensive loss | $ | (88.0) | $ | (106.1) | ||||||||
VIII. Share capital |
Under U.S. GAAP, amounts receivable for share capital should be recorded as a deduction from shareholders' equity. Under Canadian GAAP, effective Jan. 1, 2004, TransAlta has elected to prospectively present employee share purchase plan loans as a deduction from shareholders' equity thereby eliminating the difference between U.S. and Canadian GAAP as of Jan. 1, 2004. Under the corporation's employee share purchase plan, accounts receivable at Dec. 31, 2003 were $0.9 million.
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IX. Right of offset agreement
The corporation had a New Zealand bank deposit that had been offset with a New Zealand bank facility under a right of offset agreement. The arrangement did not qualify for offsetting under U.S. GAAP. During the second quarter of 2004, the corporation refinanced certain foreign operations and the bank deposit was used to settle the bank facility in full.
X. Asset retirement obligations
FASB issued Statement 143,Asset Retirement Obligations, which requires asset retirement obligations to be measured at fair value and recognized when the obligation is incurred. A corresponding amount is capitalized as part of the asset's carrying amount and depreciated over the asset's useful life. TransAlta adopted the provisions of Statement 143 effective Jan. 1, 2003.
In accordance with Canadian GAAP, the asset retirement obligations standard was adopted retroactively with restatement of prior periods. Under U.S. GAAP, the impact of adopting Statement 143 was recognized as a cumulative effect of a change in accounting principle as of Jan. 1, 2003, the beginning of the fiscal year in which the Statement was first applied. The change resulted in an after-tax increase in net earnings of $52.5 million ($82.7 million pre-tax).
XI. Guarantees
TransAlta accounts for guarantees and related contracts, for which it is the guarantor, under FASB Interpretation No. 45 (FIN 45),Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others. In accordance with FIN 45, upon issuance or modification of a guarantee on or after Jan. 1, 2003, the corporation recognizes a liability at the time of issuance or material modification for the estimated fair value of the obligation it assumes under the guarantee. TransAlta reduces the obligation over the term of the guarantee or related contract in a systematic and rational manner as risk is reduced under the obligation.
XII. Variable interest entities
In January 2003, FASB issued FIN 46, Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51. FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest, or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. In December 2003, FASB issued FIN 46R which served to clarify guidance in FIN 46. During the fourth quarter of 2003, the corporation adopted the provisions of FIN 46R with respect to special purpose entities. The adoption did not have a significant impact on the corporation's financial position, results of operations or cash flows. During the first quarter of 2004, the corporation adopted the provisions of FIN 46R related to non-special purpose entities. The corporation has considered the provisions of FIN 46R for all subsidiaries and their related power purchase, power sale or tolling agreements. Factors considered in the analysis include the duration of the agreements, how capacity and energy payments are determined, source of payment terms for fuel, as well as responsibility and payment for operating and maintenance expenses. The corporation has two wholly-owned subsidiaries in Mexico which were created to hold the corporation's 100 per cent interest in the Campeche and Chihuahua power plants. These subsidiaries were formed in 2000 and 2001, respectively, and are considered variable interest entities under FIN 46R. As a result of the forgoing considerations, the corporation has determined that the nature of the fuel purchase and power sale contracts relating to the wholly-owned Mexican operations insulate the corporation from significant variability in the cash flows relating to the assets. Therefore, TransAlta is not the primary beneficiary and does not consolidate the ent ities. Accordingly, the subsidiaries owning the Campeche and Chihuahua plants are presented as equity investments rather than consolidated subsidiaries on the consolidated financial statements. 100 per cent of the results from operations of the two plants are presented as equity income on the consolidated income statements. There was no impact to net earnings as a result of adoption of this interpretation. TransAlta wholly owns and operates the 252-MW Campeche and 259-MW Chihuahua plants which were commissioned in 2003. The plants' electrical output is sold under 25-year contracts to Mexico's government-owned utility, the Comisión Federal de Electricidad. At Sept. 30, 2004, the corporation's maximum exposure to loss is its $416.0 million investment in the two plants.
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XIII. Changes in accounting standards
On May 19, 2004, FASB issued FASB Staff Position (FSP) 106-2,Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003(the Act) that provides guidance on the accounting for the effects of the Act for employers that sponsor post-retirement health care plans that provide drug benefits. The Act introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare. TransAlta's prescription drug benefit plan in the U.S. is not material to the corporation's post-retirement benefit plan and therefore the impact of the FSP is not material to the consolidated financial statements.
S U P P L E M E N T A L I N F O R M A T I O N(Annualized) | Sept. 30, 2004 | Dec. 31, 2003 | ||||||
Closing market price | $ | 16.49 | $ | 18.53 | ||||
Price range (last 12 months) | High | 19.12 | 19.55 | |||||
Low | 15.25 | 15.36 | ||||||
Debt/invested capital (including non recourse debt) | 44.9% | 47.6% | ||||||
Debt/invested capital (excluding non recourse debt) | 38.9% | 42.5% | ||||||
Return on common shareholders' equity | 5.8% | 10.3% | ||||||
Return on invested capital | 7.1% | 9.1% | ||||||
Book value per share | $ | 12.80 | $ | 12.90 | ||||
Cash dividends per share | $ | 1.00 | $ | 1.00 | ||||
Price/earnings ratio (times) | 22.6 x | 14.7 x | ||||||
Dividend payout ratio | 134.8% | 79.0% | ||||||
Dividend coverage (times) | 3.3 x | 4.0 x | ||||||
Dividend Yield | 6.1% | 5.4% | ||||||
Cash Flow to Debt | 20.2% | 17.9% | ||||||
R A T I O F O R M U L AS
Debt/invested capital = (short-term debt + long-term debt - - cash and interest-earning investments) / (debt + preferred securities + non-controlling interests + common equity)
Return on common shareholders’ equity = net earnings/average of opening and closing common equity
Return on invested capital = (earnings before non-controlling interests and income taxes + net interest expense) / average annual invested capital
Book value per share = common shareholders’ equity / common shares outstanding
Price/earnings ratio = current year’s close / basic earnings per share
Cash flow to total debt = cash flow from operations before changes in working capital / by two-year average of total debt Dividend payout = dividends / net earnings excluding gain on discontinued operations Dividend coverage = cash flow from operating activities / common share dividends Dividend yield = dividend per common share / current period’s close price
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G L O S S A R Y O F K E Y T E R M S
Availability - | A measure of time, expressed as a percentage of continuous operation 24 hours a day, 365 |
days a year, that a generating unit is capable of generating electricity, whether or not it is | |
actually generating electricity. | |
Btu (British Thermal Unit) - | A measure of energy. The amount of energy required to raise the temperature of one pound of |
water one degree Fahrenheit, when the water is near 39.2 degrees Fahrenheit. | |
Capacity - | The rated continuous load-carrying ability, expressed in megawatts of generation equipment. |
Gigawatt - | A measure of electric power equal to 1,000 megawatts. |
Gigawatt hour (GWh) - | A measure of electricity consumption equivalent to the use of 1,000 megawatts of power over |
a period of one hour. | |
Heat rate - | A measure of conversion, expressed as Btu/MW, of the amount of thermal energy required to |
generate electrical energy. | |
Megawatt - | A measure of electric power equal to 1,000,000 watts. |
Megawatt hour (MWh) - | A measure of electricity consumption equivalent to the use of 1,000,000 watts of power over a |
period of one hour. | |
Net maximum capacity - | The maximum capacity or effective rating, modified for ambient limitations that a generating |
unit or power plant can sustain over a specific period, less the capacity used to supply the | |
demand of station service or auxiliary needs. | |
Spark spread - | A measure of gross margin per MW (sales price less cost of fuel). |
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TransAta Corporation
Box 1900, Station “M” 110 - 12th Avenue S.W.
Calgary, Alberta Canada T2P 2M1
PHONE
403.267.7110
WEB SITE
www.transalta.com
CIBC Mellon Trust Company
P.O. Box 7010 Adelaide Street Station
Toronto, Ontario Canada M5C 2W9
PHONE
Toll free in North America: 1.800.387.0825
Toronto or outside North America: 416.643.5500
FAX
416.643.5501
web site
www.cibcmellon.com
F O R M O R E I N F O R M A T I O N :
Media inquiries:
Tim Richter
Senior Advisor, Media & Government Relations
PHONE
403.267.7238
PAGER
403.213.7041
media_relations@transalta.com
Investor inquiries:
Daniel J. Pigeon
Director, Investor Relations
PHONE
1.800.387.3598 in Canada and United States
or 403.267.2520
FAX
403.267.2590
investor_relations@transalta.com
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