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EXHIBIT 13.2
TRANSALTA CORPORATION
SECOND QUARTER REPORT FOR 2006
MANAGEMENT’S DISCUSSION AND ANALYSIS
This management’s discussion and analysis (MD&A) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. See page 21 for additional information.
This MD&A should be read in conjunction with the unaudited interim consolidated financial statements of TransAlta Corporation as at and for the three and six months ended June 30, 2006 and 2005, and should also be read in conjunction with the audited consolidated financial statements and MD&A contained in our annual report for the year ended December 31, 2005. In this MD&A, unless the context otherwise requires, ‘we’, ‘our’, ‘us’, the ‘corporation’ and ‘TransAlta’ refers to TransAlta Corporation and its subsidiaries. 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 July 20, 2006. Additional informati on respecting TransAlta, including its annual information form, is available on SEDAR atwww.sedar.com.
RESULTS OF OPERATIONS
The results of operations are presented on a consolidated basis and by business segment. We have two business segments: Generation and Corporate Development & Marketing (CD&M). Our segments are supported by a corporate group that provides finance, treasury, legal, environmental health and safety, sustainable development, corporate communications, information technology, human resources and other administrative support. These corporate group overheads are allocated to the applicable business segment unless these costs are directly attributable to discontinued operations.
In this MD&A, the impact of foreign exchange fluctuations on foreign currency transactions and balances is discussed with the relevant income statement and balance sheet items. While individual balance sheet line items will be impacted by foreign exchange fluctuations, the net impact of the translation of individual items is reflected in the cumulative translation account on the consolidated balance sheets.
The following table depicts additional key financial results and statistical operating data:
TRANSALTA CORPORATION / Q2 2006 1
| | | 3 months ended June 30 | 6 months ended June 30 |
| | | 2006 | | 2005 1 | | 2006 | | 2005 1 |
| Availability (%) | | 85.1 | | 84.1 | | 91.0 | | 88.7 |
| Production (GWh) | | 10,051 | | 12,124 | | 22,495 | | 25,230 |
| Revenue | $ | 599.0 | $ | 621.2 | $ | 1,332.7 | $ | 1,305.5 |
| Gross margin2 | $ | 339.1 | $ | 345.7 | $ | 733.1 | $ | 697.3 |
| Operating income 2 | $ | 75.7 | $ | 87.8 | $ | 229.7 | $ | 221.4 |
| Net earnings | $ | 86.4 | $ | 25.8 | $ | 155.6 | $ | 75.2 |
| Basic and diluted earnings per common share | $ | 0.43 | $ | 0.13 | $ | 0.78 | $ | 0.38 |
| Cash flow from operating activities | $ | 66.8 | $ | 109.8 | $ | 267.1 | $ | 259.4 |
1TransAlta adopted the standard for stripping costs incurred in the production phase of a mining operation on Jan. 1, 2006 . SeeNote 1 to the unaudited interim consolidated financial statements for further discussion. Prior periods have been restated.
2Gross margin and operating income are not defined under Canadian GAAP. Refer to the Non-GAAP Measures section on page 18 of this MD&A for a further discussion of operating income and gross margin, including a reconciliation to net earnings.
AVAILABILITY & PRODUCTION
Availability for the three months ended June 30, 2006 was 85.1 per cent versus 84.1 per cent during the same period in 2005. Higher planned outages at the Alberta Thermal plants and at the Centralia coal-fired plant (“Centralia Coal”) were more than offset by lower planned outages at Sarnia and Poplar Creek and fewer unplanned outages at the Alberta Thermal plants and Sarnia.
Availability for the six months ended June 30, 2006 increased to 91.0 per cent from 88.7 per cent compared to the same period in 2005 primarily due to fewer unplanned outages at our Alberta Thermal plants, Sarnia, and Centralia Coal, combined with fewer planned outages at Poplar Creek and Sarnia, partially offset by higher planned outages at the Alberta Thermal plants and Centralia Coal.
Production for the second quarter decreased 2,073 gigawatt hours (GWh) compared to the same period in 2005 as a result of reduced production at the Centralia Coal plant to take advantage of market pricing, decreased hydro production, and increased planned maintenance at the Alberta Thermal plants. These decreases were partially offset by fewer unplanned outages at our Alberta coal fired facilities and higher production at Poplar Creek.
Production for the first six months of 2006 decreased 2,735 GWh compared to the same period in 2005 as a result of reduced production at Centralia Coal, hydro and at various gas plants and higher planned maintenance at the Alberta Thermal plants. These decreases were partially offset by incremental production from Genesee 3, fewer unplanned outages at the Alberta Thermal plants, and increased production at Poplar Creek.
NET EARNINGS
For the three and six months ended June 30, 2006, reported net earnings increased to $86.4 million from $25.8 million and to $155.6 million from $75.2 million compared to the same periods in 2005. For the three months ended June 30, 2006, comparable earnings1 were $31.1 million ($0.16 per common share), an increase of $5.3 million ($0.03 per common share) compared to the same period in 2005. Comparable earnings for the six months ended June 30, 2006 were $106.5 million ($0.53 per common share), an increase of $31.3 million ($0.15 per common share) over the same period in 2005.
A reconciliation of net earnings is presented below:
1Comparable earnings is not defined under Canadian GAAP. Presenting earnings on a comparable basis from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Refer to the Non-GAAP Measures section on page 18 of this MD&A for further discussion of comparable earnings, including reconciliation to net earnings.
2 TRANSALTA CORPORATION / Q2 2006
| | 3 months ended June 30 | 6 months ended June 30 |
| Net earnings, 2005 (as restated) | $ | 25.8 | $ | 75.2 |
| (Decreased) increased Generation gross margins | | (6.7) | | 38.6 |
| Higher (lower) Energy Trading margins | | 0.1 | | (2.8) |
| Decrease (increase) in operations, maintenance and administration costs | | 3.9 | | (6.3) |
| Reduced interest expense | | 13.8 | | 20.7 |
| Decreased income tax expense | | 56.9 | | 53.8 |
| Increased depreciation expense | | (9.5) | | (21.5) |
| Decrease in non-controlling interest | | 3.2 | | 1.3 |
| Other | | (1.1) | | (3.4) |
| Net earnings, 2006 | $ | 86.4 | $ | 155.6 |
Generation gross margins decreased by $6.7 million for the three months ended June 30, 2006 as a result of higher planned outages at the Alberta Thermal plants and higher costs of coal. These decreases were partially offset by fewer unplanned outages at our Alberta coal fired facilities, economic dispatch at Centralia Coal, increased production at Genesee 3, and increased revenue from Sarnia.
For the six months ended June 30, 2006, Generation gross margins increased by $38.6 million as a result of fewer unplanned outages at the Alberta Thermal plants, incremental production from Genesee 3, additional revenue from Sarnia, higher spark spreads at Poplar Creek, and higher pricing in Alberta and at Centralia Coal partially offset by higher costs of coal and reduced production at Centralia Coal.
CD&M gross margins are comparable to the same quarter last year as a result of trading positions taken in response to changing market conditions. For the six months ended June 30, 2006, CD&M gross margins decreased by $2.8 million compared to the same period in 2005 due to lower realized gains from trading activities.
Operations, maintenance and administration (OM&A) costs for the three months ended June 30, 2006 decreased by $3.9 million compared to the same period in 2005 mainly due to reduced operating costs in the Generation segment. OM&A costs for the six months ended June 30, 2006 increased by $6.3 million compared to the same period in 2005 due to general cost escalations.
Depreciation expense increased $9.5 million for the three months ended June 30, 2006 compared to 2005 primarily due to revised depreciation rates at the Ottawa, Mississauga, Windsor, Fort Saskatchewan, and Meridian plants and revised estimates of asset retirement obligations (ARO) at the Alberta Thermal plants. For the first six months of 2006, depreciation increased $21.5 million due to revised depreciation rates at the above-mentioned plants, revised estimates of ARO at the Alberta Thermal plants, and the impairment recorded in the first quarter on turbines held in inventory. The change in depreciation rates at the above-mentioned plants in both the second quarter and year to date resulted in an increase in depreciation expense which was offset by a decrease in non-controlling interest.
For the three and six months ended June 30, 2006, net interest expense declined $13.8 million and $20.7 million, respectively, due to the impact of the settlement of net investment hedges and lower debt levels. Net debt of $51.8 million and $185.9 million was retired in the three and six months ended June 30, 2006, respectively.
Income taxes decreased by $56.9 million and $53.8 million for the three and six months ended June 30, 2006, respectively, due to reduced federal and provincial tax rates. The effective tax rates, excluding the impact of the change of tax rates on previous period earnings, for the quarter and six months ended June 30, 2006 were 29.9 per cent and 26.7 per cent, respectively.
CASH FLOW
Cash flow from operating activities for the three months ended June 30, 2006 decreased $43.0 million mainly due to cash being consumed in working capital as we built our coal inventory at Centralia Coal.
TRANSALTA CORPORATION / Q2 2006 3
Cash flow from operating activities in the six months increased $7.7 million compared to the same period last year due to stronger cash earnings in the first quarter partially offset by higher cash used in working capital in the second quarter to build our coal inventory at Centralia Coal.
The key factors responsible for these changes are listed below in the reconciliation of cash flow from operating activities for the three and six months ended June 2005 to 2006:
| | 3 months ended June 30 | 6 months ended June 30 |
| Cash flow from operating activities, 2005 (as restated) | $ | 109.8 | $ | 259.4 |
| Increased cash earnings | | 65.5 | | 99.3 |
| Changes in unrealized gains from Energy Trading activities | | (7.7) | | 12.0 |
| Changes in other non-cash items | | (25.2) | | (26.0) |
| Changes in non-cash working capital | | (75.6) | | (77.6) |
| Cash flow from operating activities, 2006 | $ | 66.8 | $ | 267.1 |
At June 30, 2006, our total debt (including non-recourse debt) to invested capital ratio was 41.5 per cent (37.8 per cent excluding non-recourse debt). This represents an improvement from the December 31, 2005 ratio of 43.9 per cent (40.2 per cent excluding non-recourse debt) and from the March 31, 2006 ratio of 42.2 per cent (38.4 per cent excluding non-recourse debt).
SIGNIFICANT EVENTS
Three months ended June 30, 2006
Centralia Coal economic dispatch
During the second quarter, lower market prices allowed us to purchase power at a price lower than our variable cost of production. As a result, Centralia Coal did not operate for the majority of the second quarter. The gains from fulfilling contracts with replacement power offset to some degree lower prices. As a result, we experienced 1,936 GWh of lower production during the second quarter compared to the same period of 2005.
2006 Federal and Alberta budgets
On May 24, 2006, the Alberta budget received Royal Assent. As a result, the general corporate income tax rate was reduced from 11.5 per cent to 10 per cent effective April 1, 2006. The federal budget received Royal Assent on June 22, 2006. As a result, the general corporate income tax rate will be reduced from 21 per cent to 19 per cent by January 1, 2010. The corporate surtax has been eliminated for taxation years ended after December 31, 2007 as well as the federal capital tax has been eliminated effective January 1, 2006. The carry-forward period for non-capital losses and investment tax credits earned after 2005 has been extended from 10 to 20 years. As a result of these changes, in the second quarter the Corporation reduced income tax expense by $62.2 million which reflected the impact of these changes on current and prior years’ earnings. The impact on current y ear earnings was approximately $6.9 million.
Six months ended June 30, 2006
Sarnia power plant
On February 15, 2006, we signed a five-year contract with the Ontario Power Authority for our Sarnia Regional Cogeneration Power Plant to supply an average of 400 megawatts (MW) of electricity to the Ontario electricity market. The contract was effective January 1, 2006.
Centralia Coal derates and economic dispatch
Due to heavy rainfall in the Pacific Northwest in the first quarter of 2006, we derated Centralia Coal and started rebuilding our coal inventory. The impact of derating the plant during this time was partially offset by increasing coal imports and purchasing replacement power. We experienced 875 GWh of lower production during the first quarter compared to the same period of 2005. During the second quarter, lower market prices allowed us to purchase power at a price lower than our variable cost of production. As a result, Centralia Coal did not operate
4 TRANSALTA CORPORATION / Q2 2006
for the majority of the second quarter. We experienced 1,936 GWh of lower production during the second quarter compared to the same period of 2005. The total decrease in production in the first six months of 2006 was 2,811 GWh.
Purchase of Wailuku River Hydroelectric L.P.
On February 17, 2006 we purchased a 50 per cent interest in Wailuku River Hydroelectric L.P. through Wailuku Holding Company, LLC (“Wailuku”) for cash of USD$1.0 million (CAD$1.2 million). Wailuku had debt of USD$19.2 million (CAD$22.3 million) at the time of acquisition. Refer to Note 2 of the unaudited interim consolidated financial statements for the six months ended June 30, 2006 for the final purchase price allocation. Wailuku owns a run of the river hydro facility with an operating capacity of 10 MW. Mid American Energy Holdings Company owns the other 50 per cent interest in Wailuku.
Change in depreciation rate
In the first quarter of 2006 we changed the depreciation method of the Windsor, Mississauga, Ottawa, Meridian, and Fort Saskatchewan plants. Previously, these plants were being amortized on a unit of production method over the life of the plants. After reviewing the estimated useful life and considering the uncertainty for the plants’ operations beyond the terms of the current sales contracts, we determined that itwas more reasonable to allocate the remaining net book value of the plants on a straight line basis over the remaining term of the respective contracts.
Keephills 3 project
On March 14, 2006 we signed a development agreement with EPCOR Utilities Inc. (EPCOR) to jointly examine the development of the Keephills 3 power project, a proposed 450 MW unit adjacent to our existing Keephills facility. Development work is in the early stages, and in 2006 we will continue stakeholder consultations, focus on the regulatory process, define the commercial and financial details and complete preliminary engineering and design work.
DISCUSSION OF SEGMENTED RESULTS
GENERATION: Owns and operates hydro, wind, geothermal, gas- and coal-fired plants and related mining operations in Canada, the U.S., and Australia. At June 30, 2006, Generation had 8,366 MW of gross generating capacity1 in operation (7,962 MW net ownership interest). Generation's revenues are derived from the availability and production of electricity and steam as well as ancillary services such as system support (see the detailed discussion of the four revenue streams in our annual report for the year ended December 31, 2005).
The results of the Generation segment are as follows:
| | | | | | | | | 2005 |
| | | | | | | | | (Restated, |
| | | | | 2006 | | | | Note 1) |
| 3 months ended June 30 | | Total | P e r M W h | | Total | | Per MWh |
| Revenues | $ | 554.6 | $ | 55.18 | $ | 564.5 | $ | 46.56 |
| Fuel and purchased power | | (241.2) | | (24.00) | | (244.4) | | (20.16) |
| Gross margin | | 313.4 | | 31.18 | | 320.1 | | 26.40 |
| Operations, maintenance and administration | | 128.8 | | 12.81 | | 131.1 | | 10.81 |
| Depreciation and amortization | | 98.8 | | 9.83 | | 89.3 | | 7.37 |
| Taxes, other than income taxes | | 5.6 | | 0.56 | | 5.7 | | 0.47 |
| Intersegment cost allocations | | 7.0 | | 0.70 | | 6.5 | | 0.54 |
| Operating expenses | | 240.2 | | 23.90 | | 232.6 | | 19.19 |
| Operating income before corporate allocations | | 73.2 | | 7.28 | | 87.5 | | 7.21 |
| Corporate allocations | | 18.7 | | 1.86 | | 18.0 | | 1.48 |
| Operating income | $ | 54.5 | $ | 5.42 | $ | 69.5 | $ | 5.73 |
| Production (GWh) | | 10,051 | | | | 12,124 | | |
| Availability (%) | | 85.1 | | | | 84.1 | | |
1 TransAlta measures capacity as net maximum capacity (see glossary for definition of this and other key items) which is consistent with industry standards. Capacity figures represent capacity owned and in operation unless otherwise stated.
TRANSALTA CORPORATION / Q2 2006 5
| | | | | | | | | 2005 |
| | | | | | | | | (Restated, |
| | | | | 2006 | | | | Note 1) |
| 6 months ended June 30 | | Total | | Per MWh | | Total | | Per MWh |
| Revenues | $ | 1,234.6 | $ | 54.88 | $ | 1,177.8 | $ | 46.68 |
| Fuel and purchased power | | (536.5) | | (23.85) | | (518.3) | | (20.54) |
| Gross margin | | 698.1 | | 31.03 | | 659.5 | | 26.14 |
| Operations, maintenance and administration | | 233.2 | | 10.36 | | 228.1 | | 9.04 |
| Depreciation and amortization | | 196.9 | | 8.75 | | 175.3 | | 6.95 |
| Taxes, other than income taxes | | 11.1 | | 0.49 | | 11.4 | | 0.45 |
| Intersegment cost allocations | | 13.9 | | 0.62 | | 13.0 | | 0.52 |
| Operating expenses | | 455.1 | | 20.22 | | 427.8 | | 16.96 |
| Operating income before corporate allocations | | 243.0 | | 10.81 | | 231.7 | | 9.18 |
| Corporate allocations | | 39.2 | | 1.74 | | 36.6 | | 1.45 |
| Operating income | $ | 203.8 | $ | 9.07 | $ | 195.1 | $ | 7.73 |
| Production (GWh) | | 2 2 , 4 9 5 | | | | 25,230 | | |
| Availability (%) | | 91.0 | | | | 88.7 | | |
Market prices and spark spreads
Gas- and coal-fired facilities that have exposure to market fluctuations in energy commodity prices represent 5 per cent and 19 per cent of our total generating production, respectively. We closely monitor the risks associated with these commodity price changes on our future operations and, where we consider it appropriate; use various physical and financial instruments to hedge our assets and operations from such price risk.
6 TRANSALTA CORPORATION / Q2 2006
1 For a 7,000 Btu/KWh heat rate plant.
In the second quarter of 2006, compared to the same period in 2005, spot electricity prices were slightly higher in Alberta while they decreased in both the Pacific Northwest and Ontario. Weaker natural gas prices put downward pressure across all three regions, but year over year demand growth offset such weakness in Alberta. Improved hydro generation provided further downward pressure on prices in the Pacific Northwest while more moderate temperatures and improved nuclear generation decreased prices in Ontario. With the exception of Alberta, where strong demand growth contributed to higher spark spreads, spark spreads decreased in the second quarter of 2006 for all markets relative to the same period in 2005.
Availability
Availability for the three months ended June 30, 2006 was 85.1 per cent versus 84.1 per cent during the same period in 2005. Higher planned outages at the Alberta Thermal plants and at Centralia Coal were more than offset by lower planned outages at Sarnia and Poplar Creek and fewer unplanned outages at the Alberta Thermal plants and Sarnia.
Availability for the six months ended June 30, 2006 increased to 91.0 per cent from 88.7 per cent compared to the same period in 2005 primarily due to fewer unplanned outages at the Alberta Thermal plants and Centralia Coal, combined with fewer planned outages at Poplar Creek and Sarnia, partially offset by higher planned outages at the Alberta Thermal plants and at Centralia Coal.
Production
Production for the three months ended June 30, 2006 decreased 2,073 GWh to 10,051 GWh as compared to the same period in 2005 due to reduced production at Centralia Coal (1,936 GWh), higher planned outages at the Alberta Thermal plants (224 GWh), reduced production at Sarnia due to lower spark spreads (209 GWh), and lower hydro production (127 GWh). These decreases were partially offset by fewer unplanned outages at the Alberta Thermal plants (165 GWh) and lower planned outages at Poplar Creek and Sarnia (293 GWh).
Production for the six months ended June 30, 2006 decreased 2,735 GWh as compared to the same period in 2005 due to reduced production at Centralia Coal (2,811 GWh), higher planned outages at the Alberta Thermal plants (135 GWh), reduced spark spreads at Sarnia (367 GWh), reduced customer demand at Fort Saskatchewan (150 GWh), lower hydro production (113 GWh) and reduced production at the Ottawa plant in the first quarter where we chose to sell our natural gas rather than produce electricity (81 GWh). These decreases were partially offset by incremental production from Genesee 3 (366 GWh), fewer unplanned outages at the Alberta Thermal plants (473 GWh), and lower planned outages at Poplar Creek and Sarnia (303 GWh).
Revenue
Revenue decreased by $9.9 million for the three months ended June 30, 2006 as compared to the same period in 2005 primarily due to lower net prices at Centralia Coal ($8.1 million), higher planned outages at the Alberta Thermal plants ($10.1 million), higher planned outages at CE Generation LLC (“CE Gen”) ($3.2 million), and the strengthening of the Canadian dollar ($15.3 million) partially offset by higher revenue from Ottawa gas sales ($11.5 million), fewer unplanned outages at the Alberta Thermal plants ($8.3 million), incremental revenue from the Sarnia contract ($8.0 million), higher production at Genesee 3 ($6.8 million), and increased spark spreads at Poplar Creek ($4.0 million).
For the six months ended June 30, 2006 revenue increased $56.8 million due to improved pricing in Alberta and at Centralia Coal mainly in the first quarter ($37.4 million), lower unplanned outages at the Alberta Thermal plants ($21.2 million), incremental revenues from Genesee 3 ($22.9 million), favourable spark spreads at Poplar Creek ($8.3 million), higher revenues from Ottawa gas sales ($19.7 million), and Sarnia capacity payments ($17.6 million). These increases were partially offset by decreased production at Centralia Coal in the first quarter ($42.8 million), strengthening of the Canadian dollar ($26.5 million), lower net prices at Centralia Coal in the second quarter ($8.1 million), higher unplanned outages at CE Gen ($3.1 million), and higher planned outages at the Alberta Thermal plants ($5.9 million).
Fuel and purchased power
Fuel and purchased power decreased by $3.2 million for the three months ended June 30, 2006 compared to the same period in 2005. Increased coal costs at Centralia Coal ($13.1 million) and the Alberta Thermal plants ($5.5 million), and incremental gas purchases at Ottawa
TRANSALTA CORPORATION / Q2 2006 7
($7.3 million) were offset by the net benefit of lower production due and economic dispatching at Centralia Coal ($20.9 million) and strengthening of the Canadian dollar ($8.6 million).
Fuel and purchased power increased by $18.2 million for the six months ended June 30, 2006 compared to the same period in 2005. Increased cost of coal at Centralia Coal ($30.7 million) and at the Alberta Thermal plants ($8.5 million), incremental gas purchases at Ottawa ($9.7 million) and increased gas prices in the first quarter at other gas facilities, were partially offset by lower net production costs at Centralia Coal in the first quarter ($14.2 million), strengthening of the Canadian dollar ($14.5 million) and the net benefit of economic dispatch at Centralia Coal ($20.9 million).
Operations, maintenance and administration expense
For the three months ended June 30, 2006, OM&A expense decreased by $2.3 million compared to the same period in 2005 primarily due to general cost reductions across the fleet.
For the six months ended June 30, 2006, OM&A expense increased $5.1 million compared to the same period in 2005 due to general cost escalations.
Depreciation expense
For the three months ended June 30, 2006, depreciation expense increased $9.5 million primarily due to revised depreciation rates at the Windsor, Mississauga and Ottawa plants and revised ARO estimates at the Alberta Thermal plants. For the first six months of 2006, depreciation increased $21.6 million due to the reasons mentioned for the second quarter as well as the impairment recorded in the first quarter on turbines held in inventory.
Planned maintenance
The table below shows the amount of planned maintenance capitalized and expensed in the three and six months ended June 30, 2006 and 2005, excluding CE Gen and Mexico:
| | | | | Coal | | | Gas and Hydro | | | | Total |
| 3 months ended June 30 | | 2006 | | 2005 | | 2006 | | 2005 | | 2006 | | 2005 |
| Capitalized | $ | 27.8 | $ | 27.0 | $ | 9.8 | $ | 23.3 | $ | 37.6 | $ | 50.3 |
| Expensed | | 27.9 | | 26.2 | | 0.9 | | 1.5 | | 28.8 | | 27.7 |
| | $ | 55.7 | $ | 53.2 | $ | 10.7 | $ | 24.8 | $ | 66.4 | $ | 78.0 |
| GWh lost | | 1,379 | | 1,095 | | 93 | | 347 | | 1,472 | | 1,442 |
| | | | | Coal | | | Gas and Hydro | | | | Total |
| 6 months ended June 30 | | 2006 | | 2005 | | 2006 | | 2005 | | 2006 | | 2005 |
| Capitalized | $ | 32.7 | $ | 29.4 | $ | 12.4 | $ | 26.8 | $ | 45.1 | $ | 56.2 |
| Expensed | | 30.2 | | 30.5 | | 1.3 | | 1.6 | | 31.5 | | 32.1 |
| | $ | 62.9 | $ | 59.9 | $ | 13.7 | $ | 28.4 | $ | 76.6 | $ | 88.3 |
| GWh lost | | 1,383 | | 1,188 | | 105 | | 367 | | 1,488 | | 1,555 |
In the three months ended June 30, 2006, production lost due to planned maintenance increased to 1,472 GWh compared to 1,442 GWh lost for the same period in 2005 primarily due to higher planned outages at Alberta Thermal plants (224 GWh) and at Centralia Coal (90 GWh) offset by lower outages at Sarnia and Poplar Creek (293 GWh). Production lost in the first six months of 2006 decreased by 67 GWh due to reduced planned maintenance at the Alberta Thermal plants.
In the three and six months ended June 30, 2006, total capitalized and expensed maintenance costs are lower than the same periods in 2005 mainly due to less planned maintenance at Sarnia.
8 TRANSALTA CORPORATION / Q2 2006
Generation production volumes
Generation’s production volumes, electricity and steam production revenues and fuel and purchased power costs are presented below:
| | | | | | | | | | | Fuel & | |
| | | | | Fuel & | | | | | Purchased | Gross |
| | Production | | | Purchased | | Gross | Revenue Power per | Margin per |
| 3 months ended June 30, 2006 | (GWh) | | Revenue | Power | | Margin | per MWh | MWh | MWh |
| Alberta PPAs | 6,029 | $ | 158.6 | $ | 49.4 | $ | 109.2 | $ | 26.31 | $ 8.19 | $ 18.12 |
| Long-term contracts | 1,682 | | 154.0 | | 85.7 | | 68.3 | | 91.56 | 50.95 | 40.61 |
| Merchant | 1,664 | | 178.4 | | 91.2 | | 87.2 | 107.21 | 54.81 | 52.40 |
| CE Gen | 676 | | 63.6 | | 14.9 | | 48.7 | 94.08 | 22.04 | 72.04 |
| | 10,051 | $ | 554.6 | $ 241.2 | $ | 313.4 | $ | 55.18 | $ 24.00 | $ 31.18 |
| | | | | | | | | | | Fuel & | |
| | | | | | Fuel & | | | | | Purchased | Gross |
| | Production | | | Purchased | | | Revenue per | Power per | Margin per |
| 3 months ended June 30, 2005 (Restated, Note 1) | (GWh) | | Revenue | | Power | Gross Margin | | MWh | MWh | MWh |
| Alberta PPAs | 6,194 | $ | 161.5 | $ | 42.1 | $ | 119.4 | $ | 26.07 | $ .80 | $ .27 |
| Long-term contracts | 1,738 | | 150.7 | | 84.2 | | 66.5 | | 86.72 | 48.45 | 38.27 |
| Merchant | 3,463 | | 178.6 | | 101.3 | | 77.3 | | 51.57 | 29.25 | 22.32 |
| CE Gen | 729 | | 73.7 | | 16.8 | | 56.9 | | 101.08 | 23.04 | 78.04 |
| | 12,124 | $ | 564.5 | $ | 244.4 | $ | 320.1 | $ | 46.56 | $ 20.16 | $ 26.40 |
TRANSALTA CORPORATION / Q2 2006 9
| | | | | | | | | | | Fuel & | |
| | | | | Fuel & | | | | | Purchased | Gross |
| | Production | | | Purchased | | Gross | | Revenue | Power per | Margin per |
| 6 months ended June 30, 2006 | (GWh) | | Revenue | P o w e r | | Margin | per MWh | MWh | MWh |
| A l b e r t a P P A s | 12,762 | $ | 366.9 | $ | 108.5 | $ | 258.4 | $ | 28.75 | $ 8.50 | $ 20.25 |
| Long-term contracts | 3,271 | | 330.4 | 187.5 | | 142.9 | | 101.01 | 57.32 | 43.69 |
| Merchant | 5,181 | | 412.1 | 209.8 | | 202.3 | | 79.54 | 40.49 | 39.05 |
| CE Gen | 1,281 | | 125.2 | | 30.7 | | 94.5 | | 97.74 | 23.97 | 73.77 |
| | 22,495 | $ | 1,234.6 | $ | 536.5 | $ | 698.1 | $ | 54.88 | $ 23.85 | $ 31.03 |
| | | | | | | | | | | Fuel & | |
| | | | | | Fuel & | | | | | Purchased | Gross |
| | Production | | | Purchased | | | Revenue per | Power per | Margin per |
| 6 months ended June 30, 2005 (Restated, Note 1) | (GWh) | | Revenue | | Power | Gross Margin | | MWh | MWh | MWh |
| Alberta PPAs | 12,639 | $ | 339.1 | $ | 94.0 | $ | 245.1 | $ | 26.83 | $ .44 | $ .39 |
| Long-term contracts | 3,573 | | 312.0 | | 176.9 | | 135.1 | | 87.31 | 49.50 | 37.81 |
| Merchant | 7,664 | | 387.7 | | 214.3 | | 173.4 | | 50.59 | 27.96 | 22.63 |
| CE Gen | 1,354 | | 139.0 | | 33.1 | | 105.9 | | 102.65 | 24.44 | 78.21 |
| | 25,230 | $ | 1,177.8 | $ | 518.3 | $ | 659.5 | $ | 46.68 | $ 20.54 | $ .14 |
Alberta PPAs
Under the Power Purchase Arrangements (PPAs), we earn monthly capacity revenues, which are designed to recover fixed costs and provide a return on capital for our plants and mines. We also earn energy payments for the recovery of predetermined variable costs of producing energy, an incentive/penalty for achieving above/below the targeted availability and an excess energy payment for power production above committed capacity. Our Sundance, Keephills, Sheerness and contracted portion of the Alberta hydro assets are included in this segment.
Production for the three months ended June 30, 2006 decreased by 165 GWh compared to the same period in 2005 as a result of higher planned outages (193 GWh) and lower demand from the PPA customers (133 GWh) partially offset by fewer unplanned outages (184 GWh).
Production for the six months ended June 30, 2006 increased by 123 GWh compared to the same period in 2005 as a result of fewer unplanned outages (501 GWh) partially offset by higher planned outages (104 GWh) and lower customer demand from PPA customers (248 GWh).
Revenues for the three months ended June 30, 2006 decreased by $2.9 million ($0.24 per MWh) compared to the same period in 2005 primarily due to higher planned outages ($10.1 million) and lower indices ($2.9 million) partially offset by fewer unplanned outages ($9.3 million).
Revenues for the six months ended June 30, 2006 increased by $27.8 million ($1.92 per MWh) compared to the same period in 2005 primarily due to fewer unplanned outages ($22.7 million) and higher prices in the first quarter ($14.3 million) partially offset by higher planned outages ($5.9 million).
Fuel and replacement power costs for the three months ended June 30, 2006 increased $7.3 million ($1.39 per MWh) compared to the same period in 2005 due to an increase in cost of coal as a result of higher overburden removal and increased input costs ($5.6 million) and increased production from fewer unplanned outages ($1.2 million).
Fuel and replacement power costs for the six months ended June 30, 2006 were $14.5 million ($1.06 per MWh) higher than the comparable period in 2005 due to an increase in cost of coal as a result of higher overburden removal and increased input costs ($7.2 million) and increased production from fewer unplanned outages ($3.6 million).
Long-termcontracts
Long-term contracts typically have an original term between 10 and 25 years. Long-term contracts are typically for gas-fired cogeneration plants and have between one and four customers per plant. Revenues are derived from payments for capacity and/or the production of electrical energy and steam. The results from our Mississauga, Windsor, Wailuku, Ottawa, Fort Saskatchewan, and Meridian plants as well as the contracted portions of Sarnia, Poplar Creek, and Vision Quest are included in this segment.
10 TRANSALTA CORPORATION / Q2 2006
Production for the three months ended June 30, 2006 decreased 56 GWh compared to the same period in 2005 due to reduced customer demand at Fort Saskatchewan (48 GWh) and higher planned maintenance at Meridian (35 GWh).
Production for the six months ended June 30, 2006 decreased 302 GWh due to reduced customer demand at Fort Saskatchewan (150 GWh) and higher planned maintenance at Meridian (35 GWh) combined with lower production at Ottawa due to gas sales in the first quarter (81 GWh).
For the three months ended June 30, 2006, revenues increased slightly by $3.3 million ($4.84 per MWh). Incremental revenues from gas sales at Ottawa ($11.5 million) were mostly offset by lower amounts being charged to customers as a result of lower natural gas prices.
For the first six months of 2006, revenues increased by $18.4 million ($13.70 per MWh) primarily due to the gas sales revenue from Ottawa ($19.7 million) offset by the impact of lower natural gas prices in the second quarter.
Fuel and purchased power costs increased by $1.5 million ($2.50 per MWh) for the three months ended June 30, 2006 compared to the same periods in 2005 due to incremental gas purchases at Ottawa ($7.3 million) partially offset by lower natural gas prices.
Fuel and purchased power costs increased by $10.6 million ($7.82 per MWh) for the six months ended June 30, 2006 compared to the same periods in 2005 due to incremental gas purchases at Ottawa ($9.7 million).
Merchant
Merchant revenue is derived from production and is sold via: medium-term contract sales (typically two to ten years), short-term asset-backed trading, and spot or short-term (less than one year) forward markets. The results from Centralia Coal, Centralia Gas, Genesee 3, Wabamun, Binghamton, excess energy sales from Sundance, Keephills, Hydro, and Sheerness, and uncontracted portions of Vision Quest, Poplar Creek, and Sarnia are included in this segment.
In the second quarter of 2006, merchant production was 1,664 GWh, of which 118 GWh was contracted under short- to medium-term contracts. In the second quarter of 2005, merchant production was 3,463 GWh, of which 1,188 GWh was contracted. The decrease in total production of 1,799 GWh was primarily due to economic dispatch at Centralia Coal (1,936 GWh) and lower hydro production (126 GWh) partially offset by increased production at Poplar Creek (114 GWh), Genesee 3 (94 GWh), and Centralia Gas (43 GWh).
For the six months ended June 30, 2006, merchant production was 5,181 GWh, of which 1,258 GWh was contracted under short- to medium- term contracts. In the first six months of 2005, merchant production was 7,664 GWh of which 3,124 was contracted. The decrease in production of 2,483 GWh is due to economic dispatch and derating at Centralia Coal (2,811 GWh) and lower hydro production (114 GWh) offset by increased production from Genesee 3 (366 GWh) and higher spark spreads at Centralia Gas (33 GWh).
For the three months ended June 30, 2006, gross margins increased $9.9 million ($30.08 per MWh) compared to the same period in 2005 due to increased production at Genesee 3 ($7.8 million), incremental revenue from the Sarnia contract ($8.0 million), and favourable spark spreads at Poplar Creek ($5.7 million) offset by lower gross margins at Centralia Coal ($13.5 million).
As a result of lower prices in the Pacific Northwest, the Centralia Coal plant did not operate for the majority of the second quarter, however; this reduced revenue was largely offset by revenue gained from forward trading and hedging most medium- and short-term contracts ($8.1 million). As a result of economically dispatching Centralia Coal, less coal was consumed but was partially offset by additional replacement power purchased to meet contractual obligations resulting in a net benefit of $20.9 million. Additionally, as a result of forecasted future expenditures for the mine at Centralia, a $13.1 million adjustment was recorded in the second quarter for coal costs. Centralia Coal’s gross margins further declined from reduced sales of emission credits ($1.0 million) and the strengthening of the Canadian dollar ($2.4 million).
For the six months ended June 30, 2006, gross margins increased $28.9 million ($16.42 per MWh) due to increased production from Genesee 3 ($21.0 million), favourable spark spreads at Poplar Creek ($11.0 million), increased revenue from the Sarnia contract ($17.6 million), higher contract prices at Centralia Coal in the first quarter ($21.1 million), the net benefit of economic dispatch in the second quarter at Centralia Coal ($12.8 million), and incremental sales of emission credits ($6.2 million) partially offset by higher costs of coal at Centralia Coal ($30.7 million), and the strengthening of the Canadian dollar ($4.8 million).
TRANSALTA CORPORATION / Q2 2006 11
CEGen
Our share of CE Gen production for the three and six months ended June 30, 2006, decreased by 53 GWh and 73 GWh, respectively, when compared to the same periods in 2005 primarily due to higher planned outages at Imperial Valley and Yuma, offset by higher production at Saranac.
For the second quarter and for the first six months of 2006, gross margin decreased by $8.2 million and $11.4 million compared to the same periods in 2005 primarily due to lower production at Imperial Valley and the strengthening of the Canadian dollar compared to the U.S dollar.
CORPORATE DEVELOPMENT & MARKETING:is composed of three primary departments: Trading & Delivery Optimization, Commercial Portfolio Management and Portfolio Strategy & Execution. Operating income reported in the CD&M segment is comprised of Energy Trading activities not supported by TransAlta owned generation assets (‘Energy Trading’) combined with the directly associated operating expenses.
Our Energy Trading activities utilize a variety of instruments to manage risk, earn trading margins and gain market information. Our trading strategies consist of shorter-term physical and financial trades in regions where we have assets and the markets that interconnect with those regions. The portfolio primarily 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.
While trading products are generally consistent between periods, positions held and resulting earnings impacts will vary due to current and forecasted external market conditions. Positions for each region are established based on the market conditions and the risk reward ratio established for each trade at the time they are entered. Results therefore are generally not consistent regionally or by strategy from one reported period to the next.
OM&A costs incurred within CD&M are allocated to the Generation segment based on an estimate of operating expenses and an estimated percentage of resources dedicated to providing the support and analysis. This fixed fee inter-segment allocation is represented as a cost recovery in CD&M and an operating expense within Generation.
The results of the CD&M segment are as follows:
| | 3 months ended June 30 | | 6 months ended June 30 |
| | 2 0 0 6 | | 2005 | | 2 0 0 6 | 2005 |
| Revenues | $ 44.4 | $ | 56.7 | $ | 98.1 | $ 127.7 |
| Trading purchases | (18.7) | | (31.1) | | (63.1) | (89.9) |
| Gross margin | 25.7 | | 25.6 | | 35.0 | 37.8 |
| Operations, maintenance and administration | 8.3 | | 10.7 | | 16.4 | 18.2 |
| Depreciation and amortization | 0.4 | | 0.4 | | 0.7 | 0.8 |
| Intersegment cost allocation | (7.0) | | (6.5) | | (13.9) | (13.0) |
| Operating expenses | 1.7 | | 4.6 | | 3.2 | 6.0 |
| Operating income before corporate allocations | 24.0 | | 21.0 | | 31.8 | 31.8 |
| Corporate allocations | 2.8 | | 2.7 | | 5.9 | 5.5 |
| Operating income | $ 21.2 | $ | 18.3 | $ | 25.9 | $ 26.3 |
In the second quarter of 2006, successful physical and financial power transactions were executed in combination with effective gas strategies in the Western geographic region. This trading, combined with strong Eastern regional performance in the quarter from wide pricing differentials resulted in gross margins for the six months ending June 30, 2006 being comparable to the strong performance seen in the same period of 2005.
OM&A costs decreased $2.4 million and $1.8 million for the three and six months ended June 30, 2006, respectively, compared to the same periods in 2005 due to lower incentive estimates and the timing and nature of expenditures associated with development and project related activities. The inter-segment cost allocations are consistent with the prior comparable periods.
12 TRANSALTA CORPORATION / Q2 2006
PRICERISK MANAGEMENT
Our price risk management assets and liabilities represent the value of unsettled (unrealized) Energy Trading transactions and certain Generation asset trading transactions accounted for on a fair value basis. With the exception of physical transmission contracts and gas storage assets, the fair value of all energy trading activities is based on quoted market prices. The fair value of financial transmission contracts is based upon statistical analysis of historical data. All transmission contracts are accounted for in accordance with EITF 02-3.
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, separately by source of valuation:
| Balance Sheet | | June 30, 2006 | | Dec. 31, 2005 |
| Price risk management assets | | | | |
| - Current | $ | 71.0 | $ | 63.8 |
| - Long-term | | 6.4 | | 13.8 |
| Price risk management liabilities | | | | |
| - Current | | ( 6 0 . 9 ) | | (58.3) |
| - Long-term | | (1.5) | | (8.6) |
| Net price risk management assets outstanding | $ | 15.0 | $ | 10.7 |
The corporation seeks to actively manage its exposure to credit risk by assessing the ability of counterparties to fulfill their obligations under the related contracts prior to entering into such contracts, and continually monitors these exposures after entering into these contracts. Detailed assessments are made of the credit quality of all counterparties and, where appropriate, corporate guarantees and/or letters of credit are obtained to support the ultimate collection of these receivables. See Risk Factors and Risk Management in the MD&A in our annual report for the year ended December 31, 2005 for further discussion of credit risk exposures and management thereof.
| | | Mark to | | Mark to | | |
| Change in fair value of net assets | | Market | | Model | | Total |
| Net price risk management assets outstanding at December 31, 2005 | $ | 6.8 | $ | 3.9 | $ | 10.7 |
| Contracts realized, amortized or settled during the period | | (6.7) | | (2.8) | | (9.5) |
| Changes in values attributable to market price and other market changes | | 0.3 | | (0.6) | | (0.3) |
| New contracts entered into during the current calendar year | | 11.7 | | 2.4 | | 14.1 |
| Net price risk management assets outstanding at June 30, 2006 | $ | 12.1 | $ | 2.9 | $ | 15.0 |
For the six months ended June 30, 2006, our net price risk management assets and liabilities increased $4.3 million compared to December 31, 2005 primarily due to new contracts entered in 2006 and value changes associated with contracts in existence at both period ends partially offset by contracts being settled during the quarter. To the extent applicable, changes in net price risk management assets and liabilities are reflected within the gross margin of both the CD&M and the Generation business segments.
The maturities of the above contracts over each of the next five calendar years and thereafter are as follows:
| | | | | | | | | | | | 2011 and | |
| | | 2006 | | 2007 | | 2008 | | 2009 | | 2010 | thereafter | Total |
| Prices actively quoted | $ | 6.2 | $ | 1.4 | $ | 2.3 | $ | 1.3 | $ | 0.9 | $ - | $ 12.1 |
| Prices based on models | | 2.9 | | - | | - | | - | | - | - | 2.9 |
| | $ | 9.1 | $ | 1.4 | $ | 2.3 | $ | 1.3 | $ | 0.9 | $ - | $ 15.0 |
Our Energy Trading activities are mainly transactions under 18 months in duration, thereby reducing credit risk and working capital requirements. Transactions extending past 2007 are generally Generation asset-backed contracts that do not qualify for hedge accounting and have a low risk profile including long-term fixed for floating power swaps and heat rate swaps. Changes in trading positions from December 31, 2005 to June 30, 2006 are due to changing market conditions and corresponding regional strategy positioning.
TRANSALTA CORPORATION / Q2 2006 13
| | Electricity | Natural Gas |
| Units (000s) | (MWh) | (GJ) |
| Fixed price payor, notional amounts, June 30, 2006 | 23,867 | 9,599 |
| Fixed price payor, notional amounts, December 31, 2005 | 19,315 | 11,126 |
| Fixed price receiver, notional amounts, June 30, 2006 | 24,644 | 8,570 |
| Fixed price receiver, notional amounts, December 31, 2005 | 19,047 | 12,158 |
| Maximum term in months, June 30, 2006 | 39 | 18 |
| Maximum term in months, December 31, 2005 | 24 | 12 |
NET INTEREST EXPENSE
| | | 3 months ended June 30 | | | 6 months ended June 30 | |
| | | 2 0 0 6 | | 2005 | | 2006 | | 2005 |
| Interest on recourse and non-recourse debt | $ | 37.2 | $ | 48.4 | $ | 75.0 | $ | 92.9 |
| Interest on preferred securities | | 3.4 | | 3.4 | | 6.8 | | 9.7 |
| Interest income | | (2.6) | | 0.0 | | (3.3) | | - |
| Capitalized interest | | - | | 0.0 | | - | | (3.4) |
| Net interest expense | $ | 38.0 | $ | 51.8 | $ | 78.5 | $ | 99.2 |
For the three months and six months ended June 30, 2006, net interest expense was $13.8 million and $20.7 million lower than the comparable periods in 2005 due to lower debt levels, the strengthening of the Canadian dollar compared to the U.S. dollar, and settlement of investment hedges.
NON-CONTROLLING INTERESTS
The earnings attributable to non-controlling interests in the three and six months ended June 30, 2006 decreased to $4.0 million from $7.2 million and $22.9 million from $24.2 million, respectively, compared to the same periods in 2005 as a result of changes in depreciation at the Ontario gas plants.
EQUITY INCOME
Equity income represents the results from the wholly owned subsidiaries that hold our interests in the Campeche and Chihuahua plants.
| | 3 months ended June 30 | | 6 months ended June 30 | |
| | | 2006 | | 2005 | | 2006 | 2005 |
| Availability (%) | | 85.0 | | 94.6 | | 88.1 | 94.4 |
| Production (GWh) | | 876 | | 722 | | 1,488 | 1,430 |
| Equity income | $ | 2.0 | $ | 4.9 | $ | 1.0 | $ 6.0 |
Availability decreased for the three months and six months ended June 30, 2006 as a result of a planned outage at the Chihuahua plant. Production increased during the same periods as a result of higher customer demand at both facilities.
For the three months ended June 30, 2006, equity income decreased mainly due to the strengthening of the Canadian dollar. For the first six months of 2006, the income decreased due to the strengthening of the Canadian dollar and the recognition of the deferred financing fees of $7.2 million for the Campeche project loan. We have given the lender irrevocable notice that we intend to repay the remaining balance of USD$118.3 million (CAD$137.2 million).
14 TRANSALTA CORPORATION / Q2 2006
INCOME TAXES
| | | 3 months ended June 30 | | | 6 months ended June 30 | |
| | | | | 2005 | | | | 2005 |
| | | 2006 | (Restated, Note 1) | | 2 0 0 6 | (Restated, Note 1) |
| Earnings before income taxes | $ | 34.5 | $ | 30.8 | $ | 127.5 | $ | 100.9 |
| Income tax prior to adjustment for rate change | | 10.3 | | 5.0 | | 34.1 | | 25.7 |
| Change in tax rate related to current period | | (6.9) | | - | | (6.9) | | - |
| Change in tax rate related to prior periods | | (55.3) | | - | | (55.3) | | - |
| Income tax (recovery) expense | | (51.9) | | 5.0 | | (28.1) | | 25.7 |
| Net income | $ | 86.4 | $ | 25.8 | $ | 155.6 | $ | 75.2 |
| Effective tax rate (%) | | 29.9 | | 16.2 | | 26.7 | | 25.5 |
Tax expense decreased in the second quarter of 2006 compared to the same period last year as a result of the reduction in the Canadian corporate tax rate.
FINANCIAL POSITION
The following chart outlines significant changes in the consolidated balance sheet from December 31, 2005 to June 30, 2006:
| Increase/ | |
| | (Decrease) | Explanation |
| Cash and cash equivalents | $ (24.3) | Refer to Consolidated Statements of Cash Flows |
| Accounts receivable | (219.5) | Energy Trading activities, lower prices and reduced production at Centralia |
| | | Coal |
| Prepaid expenses | 21.4 | Insurance premiums and other prepaids |
| Inventory | 92.8 | Higher coal inventory at Centralia Coal |
| Long-term receivables | 32.6 | Revised ARO estimate |
| Property, plant and equipment, net of accumulated depreciation | (104.4) | Increased depreciation and turbine impairment partially offset by capital |
| | | additions and revised ARO adjustment |
| Intangible assets | (38.6) | Amortization and strengthening of the Canadian dollar compared to the U.S. |
| | | dollar |
| Other assets (including current portion) | (25.0) | Realized gain on settlement of net investment hedges and mark to market |
| | | changes on hedging derivatives |
| Short-term debt | 87.7 | Net increase in short-term debt |
| Accounts payable and accrued liabilities | (159.5) | Decreased Energy Trading activitiy and timing of major maintenance |
| | | activities |
| Income taxes payable | (10.6) | Paid installments offset by current tax provision |
| Recourse long-term debt (including current portion) | (262.8) | Debt repayments and stronger Canadian dollar compared to the U.S. dollar |
| Non-recourse long-term debt (including current portion) | (29.4) | Repayment of long-term debt |
| Deferred credits and other long-term liabilities (including current portion) | 60.3 | Revised ARO estimate |
| Net future income tax liabilities (including current portions) | (48.6) | Tax benefit from tax rate reduction |
| Non-controlling interests | (11.0) | Reduced earnings at subsidiaries |
| Shareholders’ equity | 96.7 | Net earnings for the period, dividend reinvestment program and share |
| | | issuances, offset by dividends |
TRANSALTA CORPORATION / Q2 2006 15
STATEMENTS OF CASH FLOWS
| 3 months ended June 30 | 2006 | | 2005 | Explanation |
| Cash and cash equivalents, beginning of period | $ 89.5 | $ | 104.5 | |
| Provided by (used in): | | | | |
| Operating activities | 66.8 | | 109.8 | Increased cash earnings offset by increased working capital balances. |
| Investing activities | (5.1) | | (106.4) | In 2006, cash outflows were primarily due to additions to property, plant and equipment |
| | | | | of $68.7 million offset by realized foreign exchange gains on investments of $45.9 |
| | | | | million. |
| | | | | In 2005, cash outflows were primarily due to additions to property, plant and equipment |
| | | | | of $107.6 million. |
| Financing activities | ( 9 9 . 9 ) | | (46.7) | In 2006, cash outflows were due to repayment of short- and long-term debt of $51.8 |
| | | | | million, dividends on common shares of $33.1 million and distributions to |
| | | | | subsidiaries' non-controlling interests of $16.9 million. |
| | | | | In 2005, cash outflows were due to repayment of short- and long-term debt of $37.4 |
| | | | | million and distributions to subsidiaries' non-controlling interest of $17.2 million. |
| Translation of foreign currency cash | 3.7 | | (2.9) | |
| Cash and cash equivalents, end of period | $ 55.0 | $ | 58.3 | |
| 6 months ended June 30 | 2006 | | 2005 | Explanation |
| Cash and cash equivalents, beginning of period | $ 79.3 | $ | 101.2 | |
| Provided by (used in): | | | | |
| Operating activities | 267.1 | | 259.4 | Increased earnings offset by higher working capital requirements. |
| Investing activities | (17.0) | | (155.0) | Capital expenditures of $97.9 million, offset realized gains on net investment hedges |
| | | | | $64.6 million, proceeds on sale of assets of $9.2 million and increase in equity |
| | | | | investments of $8.2 million. |
| | | | | In 2005, cash outflows were primarily due to additions to property, plant and |
| | | | | equipment of $145.3 million. |
| Financing activities | (277.2) | | (143.6) | In 2006, the cash used in financing activities increased due to repayment of long-term |
| | | | | debt of $272.2 million, distributions to the subsidiaries' non-controlling interest of |
| | | | | $34.1 million and dividend payments of $66.0 million partially offset by an increase in |
| | | | | short-term debt of $86.3 million. |
| | | | | In 2005, cash outflows were due to the redemption of preferred securities of $300.0 |
| | | | | million, dividends on common shares of $35.6 million, distribution to subsidiaries' |
| | | | | non-controlling interests of $35.6 million and repayment of long-term debt of $21.9 |
| | | | | million partially offset by an increase in short-term debt of $231.7 million. |
| | 2.8 | | (3.7) | |
| Translation of foreign currency cash | | | | |
| Cash and cash equivalents, end of period | $ 55.0 | $ | 58.3 | |
Funds generated from operations
Funds generated from operations were $66.8 million for the three months ended June 30, 2006, compared to $109.8 million for the same period in 2005. The decrease in funds generated was caused by higher working capital balances to build coal inventory at Centralia Coal partially offset by higher cash earnings.
For the six months ended June 30, 2006, funds generated from operations were $267.1 million compared to $259.4 million in 2005 as a result of higher cash earnings largely offset by working capital used to build our coal inventory at Centralia Coal.
Investing activities
Capital expenditures for the three months ended June 30, 2006 were $68.7 million compared to $107.6 million for the same period in 2005. The decrease was mainly due to capital spending on Genesee 3 in 2005, as well as reduced capital spending on maintenance and at our mines. For the six months ended June 30, 2006, capital expenditures were $97.9 million compared to $145.3 million for the same reasons noted above.
For the three and six months ended June 30, 2006, the corporation realized positive cash flows of $45.9 million and $64.6 million from the settlement of net investment hedges of foreign subsidiaries compared to $8.3 million and $3.3 million, respectively, in the same periods in 2005. This increase was due to the strengthening of the Canadian dollar against the U.S. dollar.
16 TRANSALTA CORPORATION / Q2 2006
Financing activities
Cash used in financing activities during the quarter was $99.9 million compared to $46.7 million over the same quarter for 2005. This increase was mainly due to timing of dividends on common shares ($30.5 million) and from repayment of short-term debt. For the first six months of 2006, cash used in financing activities was $277.2 million compared to $143.6 million in the same period in 2005. This increase was due to timing of dividend payments and a net decrease in long- and short-term debt balances.
LIQUIDITY AND CAPITAL RESOURCES
Liquidity risk arises from our ability to meet general funding needs, engage in trading and hedging activities and manage the assets, liabilities and capital structure of the company. Liquidity risk is managed to maintain sufficient liquid financial resources to fund obligations as they become due in the most cost-effective manner.
Our liquidity needs are met through a variety of sources, including: cash generated from operations, short-term borrowings against our credit facilities, and commercial paper program and long-term debt issued under the corporation’s U.S. shelf registrations and Canadian Medium Term Note program. Our primary uses of funds are operational expenses, capital expenditures, dividends, distributions to non-controlling limited partners and interest and principal payments on debt securities.
We have a $1.5 billion committed syndicated credit facility and approximately $331.9 million of uncommitted credit facilities. At June 30, 2006, we had $1.2 billion available under these credit facilities (December 31, 2005 - $1.2 billion).
We have obligations to issue letters of credit to secure potential liabilities to certain parties including those related to potential environmental obligations, trading activities, hedging activities and purchase obligations. At June 30, 2006, we had issued letters of credit totaling $534.9 million compared to $694.6 million at December 31, 2005. The decrease in letters of credit is due primarily to lower electricity spot prices in the Pacific Northwest.
We expect that our ability to generate adequate cash flow from operations in the short-term and the long-term and, when needed, to maintain financial capacity and flexibility to provide for planned growth remains substantially unchanged since December 31, 2005.
On July 20, 2006, we had approximately 201.3 million common shares outstanding.
Guarantee contracts
We have provided guarantees of subsidiaries' obligations that secure those subsidiaries’ obligations to third parties under various contracts. The guarantees generally have limits as to the amount of the guarantees however we also have a number of unlimited guarantees. These guarantees fall into three categories: those related to trading activities, those related to hedging activities (hedging of the sale of electricity from production from our power plants and hedging of our interest rate and foreign exchange exposures), and those related to performance and payment obligations. To the extent potential liabilities related to these guarantees exist for trading activities, they are included in accounts payable and accrued liabilities and price risk management liabilities. To the extent potential liabilities exist related to those guarantees for hedging activities, they are not recognized on the consolidated balance sheet. To the extent liabilities exist under these guarantees for payment and performance obligations, they are included in accounts payable and accrued liabilities.
The total guarantees provided relating to trading and hedging activities amount to approximately $2.0 billion at June 30, 2006 (December 31, 2005 - $1.8 billion). The net potential liability at June 30, 2006 under these guarantees was $392.9 million (December 31, 2005 - $559.7 million). The decrease is due to lower electricity spot prices in the Pacific Northwest.
The total guarantees related to payment and performance obligations at June 30, 2006 were $683.0 million (December 31, 2005 - $645.3 million).
TRANSALTA CORPORATION / Q2 2006 17
OUTLOOK
The key factors affecting the financial results for the remainder of 2006 are the megawatt capacity in place, the availability of and production from generating assets, the margins applicable to non-contracted production, the costs of production, and the margins achieved on Energy Trading activities.
Production and availability
Generating capacity is expected to be consistent with June 30, 2006 levels. Availability in the remainder of the year is expected to improve due to reduced planned maintenance. Production is expected to increase over the same time periods as Centralia Coal is not forecast to be economically dispatched along with reduced planned maintenance.
Power prices
Electricity prices for the remainder of 2006 are anticipated to be stronger than those observed in the first half of the year in all markets due to stronger year end natural gas prices, year over year demand growth and only marginal supply additions. The Pacific Northwest is anticipated to receive the greatest upside as hydro generation moderates with the end of the run-off season. For similar reasons, spark spreads are also anticipated to be higher than those seen in the first half of the year in all markets.
Exposure to volatility in electricity prices and spark spreads is substantially mitigated through firm-price, long-term electricity sales contracts and hedging arrangements. For the balance of 2006, approximately 92.0 per cent of plant capability is contracted, of which a significant portion relates to the Alberta PPAs, which are based on achieving specified availability rates. We continue to manage future price exposure as market liquidity exists.
Fuel costs
Mining coal is subject to cost increases due to inflation and diesel commodity prices, which the corporation seeks to mitigate through diesel hedges. Seasonal variations in coal mining are minimized through the application of standard costing.
Exposure on gas costs for facilities under long-term sales contracts are minimized to the extent possible through long-term gas purchase contracts or corresponding offsets within revenues. Merchant gas facilities are exposed to the changes in spark spreads, discussed in the power prices section. We have not entered into fixed commodity agreements for gas for these merchant plants as gas will be purchased coincident with spot pricing.
Centralia coal
Coal costs for the balance of 2006 are expected to be around $50 million higher than last year due to maturity of the mine and from higher amounts of overburden being removed and handled. Offsets to these increased costs have been found throughout the business in both revenue and costs so that our overall company plan remains in line with expectations.
Operations, maintenance and administration costs
OM&A costs per MWh fluctuate by quarter and are dependent on the timing and nature of maintenance activities. OM&A costs per MWh for the remainder of the year are forecast to be lower due to lower planned maintenance activities and increased production.
Capital expenditures
Our capital expenditures are comprised of spending on sustaining our current operations and for growth activities. The two components are described in greater detail below.
Sustaining expenditures
Sustaining expenditures include planned maintenance, regular expenditures on plant equipment, systems and related infrastructures, as well as investments in our mines. For 2006, our estimate for total sustaining expenditures is between $235 million and $250 million, excluding Mexico. Of this amount, approximately $45 million is allocated to our mines.
18 TRANSALTA CORPORATION / Q2 2006
During 2006, we expect to spend between $150 million and $170 million on planned maintenance as outlined in the following table (excluding CE Gen & Mexico):
| | | Gas and | |
| | Coal | Hydro | Total |
| Capitalized | $60-65 | $35-40 | $95-105 |
| Expensed | 55-60 | 0-5 | 55-65 |
| | $115-125 | $35-45 | $150-170 |
| GWh lost | 2,050-2,150 | 250-275 | 2,300-2,425 |
We expect to lose approximately 2,375 GWh of production due to planned maintenance during 2006. In 2006, we expect to capitalize $10.5 million on planned maintenance activities in Mexico and lose approximately 275 GWh. Approximately 35 per cent of our planned maintenance expenditures are expected to occur in the third quarter.
Growth expenditures
For 2006, our growth expenditures are estimated to be between $15 million and $20 million. Financing for these expenditures is expected to be provided by cash flow from operations.
Exposure to fluctuations in foreign currencies
Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the U.S. dollar by offsetting foreign denominated assets with foreign denominated liabilities. We also have foreign currency expenses, primarily interest charges, which offset foreign currency revenues.
Net interest expense
Net interest expense for 2006 is expected to continue to decline compared to 2005 as a result of lower debt levels. However, higher interest rates and changes in the value of the Canadian dollar to the U.S. dollar could offset the benefit of lower debt levels.
Liquidity and capital resources
With the increased volatility in power and gas markets, market trading opportunities are expected to increase, which can potentially cause the need for additional liquidity. To mitigate this liquidity risk, the corporation maintains a $1.5 billion committed credit facility and monitors exposures to determine any liquidity requirements.
NON-GAAP MEASURES
We evaluate our performance and the performance of our business segments using a variety of measures. Those discussed below are not defined under GAAP and therefore should not be considered in isolation or as an alternative to or more meaningful than, net income or cash flow from operations as determined in accordance with GAAP as an indicator of the corporation’s financial performance or liquidity. These measures are not necessarily comparable to a similarly titled measure of another company.
Each business unit assumes responsibility for its operating results measured to gross margin and operating income. Operating income provides management and investors with a measurement of operating performance which is readily comparable from period to period.
TRANSALTA CORPORATION / Q2 2006 19
Gross margin and operating income are reconciled to net earnings below:
| | 3 months ended June 30 | | 6 months ended June 30 |
| | | 2006 | | 20051 | | 2006 | | 20051 |
| Gross margin | $ | 339.1 | $ | 345.7 | $ | 733.1 | $ | 697.3 |
| Operating expenses | | (263.4) | | (257.9) | | (503.4) | | (475.9) |
| Operating income | | 75.7 | | 87.8 | | 229.7 | | 221.4 |
| Foreign exchange loss | | (1.2) | | (2.9) | | (1.8) | | (3.1) |
| Net interest expense | | (38.0) | | (51.8) | | (78.5) | | (99.2) |
| Equity income | | 2.0 | | 4.9 | | 1.0 | | 6.0 |
| Earnings before non-controlling interests and income taxes | | 38.5 | | 38.0 | | 150.4 | | 125.1 |
| Non-controlling interests | | 4.0 | | 7.2 | | 22.9 | | 24.2 |
| Earnings before income taxes | | 34.5 | | 30.8 | | 127.5 | | 100.9 |
| Income tax (recovery) expense | | (51.9) | | 5.0 | | (28.1) | | 25.7 |
| Net earnings | $ | 86.4 | $ | 25.8 | $ | 155.6 | $ | 75.2 |
1TransAlta adopted the standard for stripping costs incurred in the production phase of a mining operation on Jan. 1, 2006. See Note 1 to the unaudited interim consolidated financial statements for further discussion. Prior periods have been restated.
Presenting earnings on a comparable basis from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Because we believe the turbine impairment charge recorded in the first quarter and tax rate change adjustment related to prior period earnings in the second quarter would otherwise affect the comparability of our results from period to period, we have excluded those items to calculate earnings on a comparable basis.
| | 3 months ended June 30 | | 6 months ended June 30 |
| | | 2006 | | 20051 | | 2006 | | 20051 |
| Earnings on a comparable basis | $ | 31.1 | $ | 25.8 | $ | 106.5 | $ | 75.2 |
| Turbine impairment, net of tax | | - | | - | | (6.2) | | - |
| Change in tax rate related to prior periods | | 55.3 | | - | | 55.3 | | - |
| Net earnings | $ | 86.4 | $ | 25.8 | $ | 155.6 | $ | 75.2 |
| Weighted average common shares outstanding in the period | | 200.5 | | 195.3 | | 200.3 | | 195.7 |
| Earnings on a comparable basis per share | $ | 0.16 | $ | .13 | $ | 0.53 | $ | 0.38 |
1TransAlta adopted the standard for stripping costs incurred in the production phase of a mining operation on Jan. 1, 2006. See Note 1 to the unaudited interim consolidated financial statements for further discussion. Prior periods have been restated.
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Free cash flow is intended to demonstrate the amount of cash we have available to invest in capital growth initiatives, repay recourse debt or repurchase common shares.
The reconciliation between cash flow from operations and free cash flow is calculated below:
| | 3 months ended June 30 | | | 6 months ended June 30 | |
| | | 2006 | | 2005 | | 2 0 0 6 | | 2005 |
| Cash flow from operating activities | $ | 66.8 | $ | 109.8 | $ | 267.1 | $ | 259.4 |
| Less: | | | | | | | | |
| Sustaining capital expenses | | 65.6 | | 93.1 | | 91.2 | | 118.6 |
| Dividends on common shares | | 33.1 | | 2.6 | | 66.0 | | 35.6 |
| Distribution to subsidiaries' non-controlling interest | | 16.9 | | 17.2 | | 3 4 . 1 | | 35.6 |
| Non-recourse debt repayments | | 17.0 | | 10.8 | | 25.5 | | 18.5 |
| Add: | | | | | | | | |
| Equity income and equity investment | | 6.5 | | (11.0) | | 7.2 | | (22.6) |
| Free cash flow | $ | (59.3) | $ | (24.9) | $ | 57.5 | $ | 28.5 |
SELECTED QUARTERLY INFORMATION 1
(in millions of Canadian dollars except per share amounts)
| | Q3 2005 | Q4 2005 | Q1 2006 | | Q 2 2 0 0 6 |
| Revenue | $ 722.9 | $ 810.1 | $ 733.7 | $ | 5 9 9 . 0 |
| Earnings from continuing operations | 51.2 | 47.9 | 69.2 | | 86.4 |
| Net earnings | 51.2 | 59.9 | 69.2 | | 86.4 |
| Basic earnings per common share: | | | | | |
| Continuing operations | 0.26 | 0.24 | 0.35 | | 0.43 |
| Net earnings | 0.26 | 0.30 | 0.35 | | 0.43 |
| Diluted earnings per common share: | | | | | |
| Continuing operations | 0.26 | 0.24 | 0.35 | | 0.43 |
| Net earnings | 0.26 | 0.30 | 0.35 | | 0.43 |
| | | | | | |
| | Q3 2004 | Q4 2004 | Q1 2005 | | Q2 2005 |
| Revenue | $ 678.2 | $ 660.1 | $ 684.3 | $ | 621.2 |
| Earnings from continuing operations | 33.7 | 65.9 | 49.4 | | 25.8 |
| Net earnings | 33.7 | 65.9 | 49.4 | | 25.8 |
| Basic earnings per common share: | | | | | |
| Continuing operations | 0.17 | 0.34 | 0.25 | | 0.13 |
| Net earnings | 0.17 | 0.34 | 0.25 | | 0.13 |
| Diluted earnings per common share: | | | | | |
| Continuing operations | 0.17 | 0.34 | 0.25 | | 0.13 |
| Net earnings | 0.17 | 0.34 | 0.25 | | 0.13 |
1 TransAlta adopted the standard for stripping costs incurred in the production phase of a mining operation on Jan. 1, 2006. See Note 1 to the unaudited interim consolidated financial statements for further discussion. Prior periods have been restated.
TRANSALTA CORPORATION / Q2 2006 21
CONTROLS AND PROCEDURES
As of the end of the period covered by this quarterly report, TransAlta’s management, together with TransAlta’s President and Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the design and operation of the company’s disclosure controls and procedures. Based on this evaluation, the President and Chief Executive Officer have concluded that the disclosure controls and procedures of the company are effective.
There were no changes in TransAlta’s internal control over financial reporting during the most recent fiscal quarter that have materially affected or are reasonably likely to materially affect TransAlta’s internal control over financial reporting.
FORWARD-LOOKING STATEMENTS
This MD&A and other reports and filings made with the securities regulatory authorities include forward-looking statements. All forward-looking statements are based on TransAlta Corporation's beliefs and assumptions based on information available at the time the assumption was made. In some cases, forward-looking statements can be identified by terms such as ‘may’, ‘will’, ‘believe’, ‘expect’, ‘potential’, ‘enable’, ‘continue’ or other comparable terminology. The forward-looking statements relate to, among other things, statements regarding the anticipated business prospects and financial performance of TransAlta. 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 performanc e to be materially different from those projected, including those material risks discussed in this MD&A under the heading ‘Outlook’ and in the MD&A in our annual report for the year ended December 31, 2005 under the heading ‘Risk Factors and Risk Management’. Some of the risks, uncertainties, and factors include, but are not limited to: legislative and regulatory developments that could affect revenues, costs, cost and availability of fuel to produce electricity, 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 where TransAlta Corporation operates; results of financing efforts; changes in counterparty risk; and the impact of accounting standards issued by Canadian standard setters. Given these uncertainties, the reader should not place undue reliance on these forward- looking statements which is given as of the date it is expressed in this MD&A or otherwise and TransAlta undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, except as required by law.
22 TRANSALTA CORPORATION / Q2 2006
