Hydro Tasmania has spare peak capacity that could be used to meet energy needs in other parts of Australia, according to Roger Gill, general manager of the generation division. ‘Tasmania’s system was built as an isolated system and it has a large amount of storage – around one and a half years of Tasmania’s current energy requirement, or around 14TWh. Our largest lake is five times the size of Sydney Harbour,’ says Gill. ‘We have 2260MW of installed capacity, while our peak demand is only 1600MW. We have about 600MW of peaking reserve because we have seven catchments with varying water patterns.’

According to Gill the state also has other natural resources that can be tapped: ‘We have one of the best wind resources in the world, because we are at the ‘roaring 40s’ – the only other land mass to the west at this latitude is Tiera del Fuego. We think there is 500-1000MW of potential installed capacity there that is now untapped.’

The west coast has an 8-9m/sec annual average wind speed. In comparison, the average in Denmark – which has invested heavily in wind power – is 5-8m/sec. Hydro Tasmania is beginning to develop this natural asset. ‘We now have the rights for a 130MW wind farm site, and are looking for a joint venture to develop it fully,’ says Gill, adding that the business is already building the first 10.5MW, using 1.75MW wind turbines made by Vestas in Denmark. That first stage of the wind farm is due to be in operation by May 2002.

However, Hydro Tasmania’s long term plans are more adventurous than simple growth to meet its own needs. It aims to expand its market beyond its own island into mainland Australia, using its natural resources to do so.

‘Our challenge is that we have a population of 500,000 people and limited growth,’ says Gill. ‘Soon gas will be imported from southern Australia to provide additional baseload capacity, so we need to find an alternative market. That will be the National Electricity Market (NEM).’

The NEM connects generators and wholesalers throughout New South Wales, South Australia, Victoria, the Australian Capital Territory and Queensland. Electricity is bid into a ‘pool’ mechanism, which determines prices each half-hour, and is distributed via an open access transmission network to local wholesalers. ‘The NEM is one of the more successful electricity markets,’ says Gill, ‘but the projected need for new peaking capacity in Victoria is around 3000MW in the next ten years.’

Paul Price of the National Electricity Market Management Company (NEMMCO) agrees that new peaking capacity is needed in both Victoria and South Australia. ‘The peak summer price is driving investment,’ he says. ‘There is a stack of new peaking capacity being proposed and built: we expect 750MW to come on line in Victoria and South Australia, and that will all be gas turbines.’ According to other sources in Victoria, prices have already gone up from US$12.4/MWh, when the generators were losing money, and now the baseload price averages US$22.3/MWh. At times of summer peak, the price can hit thousands of dollars.

‘Hydro is great in a peak market,’ says Gill. ‘The market is well established with an off peak-peak price spread, so it is interesting for us.’

Before Tasmania can consider taking advantage of the NEM, it must be linked to the market across Bass Strait – a project that is already under development. ‘The Basslink undersea cable is a project being developed by the UK’s National Grid as a 285km long HVDC cable,’ says Gill. ‘Nominally it is a 480MW cable but has been designed to operate for up to 10 hours at 600MW to meet export peaks, so long as it runs ‘cool’ – at 300MW – when it is importing (to Tasmania) at off-peak times. This is a world’s first in utilising the physical capacities of the cable and converters. The cost will be around US$247M, but this way it reduces the cost while maximising the benefits.’

Basslink is due to go into operation in late 2003, but is currently still under the environmental assessment process – one of the most rigorous assessments in Australian history, Gill notes. It includes issues along the power corridor as well as the maritime issues that arise in using a monopole link.

An issue for Hydro Tasmania, according to Gill, is how it manages the maintenance and upgrading of equipment, as it moves from being a mixed generating base towards a peaking energy supplier. ‘From a current generating band of 1600MW varying down to 900MW, we will move to a 2000MW peak load (when the business is supplying both Tasmania and NEM customers) and 600MW or so in the evenings. This is a change in our operating regime to allow us to import at low cost and export at peak, and arbitrage the spot price,’ explains Gill. The riverine impact of this change, in which peak load on the state’s hydro plants shifts to the morning and evening, is also being considered in the environmental assessment.

Basslink has widespread support but the outcome of the environmental approvals process is not yet known. NEMMCO’s Paul Price explains that, in general, there are significant impediments to new interconnection. ‘The regulatory test is onerous, the process of evaluating tests is difficult, and there are issues of conflict in the inter-regional planning committees,’ he says. ‘There are state jurisdictional planning bodies and that has meant that transmission planning has been more effective within states than it has for interconnection.’

Speaking about the Basslink in particular, Price notes that the current sticking point is construction of the line when it meets the mainland at Gippsland. The project calls for overhead lines but the locals want the lines to be underground, a requirement that might endanger the project’s economics.

The economic edge

The bottom line in interconnection planning is that it has to offer a return on investment, and here Basslink is aided by Tasmania’s wind potential, together with new Australian requirements to bring additional renewable energy on line.

So, what is the role of the new wind turbines? Any hydro system is vulnerable to hydrological factors: low rainfall means a shortage of ‘fuel’ for the power station. This danger was, after all, the reason why Tasmania invested heavily in water storage capacity and it is still not immune to the danger. Inflow to its lake system varies by +/- 30% annually. The weakness of wind turbines, in contrast, is that they are never entirely predictable, even in the ‘roaring 40s’ wind cannot be guaranteed. Bringing the two together, however, minimises those weaknesses. ‘The beauty of it,’ says Gill, ‘is that the wind capacity can hook in to Tasmania’s hydro.

‘Using the wind we can time shift energy – we can run it into the grid, turn off the hydro and save water, then when the wind is not supplying we can run down the hydro.’

This is a ‘quasi pumped storage’ system, Gill explains, and it means the business does not need to invest in the real thing. As the wind turbines and Basslink help Hydro Tasmania manage its hydrological risk, it allows the business to take on different risks – and rewards. ‘We will take on a market risk,’ says Gill, ‘but we will lose the hydro risk.’

According to Gill, the company is preparing to take on that risk. Tasmania has already been deregulated, with generation devolved to Hydro Tasmania, and separate companies set up for transmission and distribution. ‘There are some regulatory matters to be completed but those are falling into place,’ Gill adds. ‘We are gearing up to be a trading business and we have started to recruit.’

Australian energy markets

New developments in Australia’s energy markets make wind turbines a much less risky investment prospect than they were in the past. Most importantly, in the financial year ending April 2002, for the first time wholesale electricity distribution companies with grids of 100MW or more will be required to source part of their supply from new renewable sources, brought on line since 1997. The requirement totals 300GWh in the first year and will increase over ten years. Between 2010 and 2020, wholesalers will have to source 9500GWh of renewable energy annually.

The system will be administered by the Renewable Energy Regulator – David Rossiter – whose office was set up at the start of this year. The requirement is part of Australia’s efforts to address greenhouse gas production, and the result will be an additional income stream for new renewable energy providers.

‘Our share of renewables was 10.5% in 1997 but because there was no growth in the sector the proportion of renewables was decreasing. Now it is nearer 9.5% of the market,’ Rossiter says.

The production of renewable energy will be administered by a certification scheme. Each MWh of electricity generated from a qualifying renewable source will also generate a certificate. At the end of each financial year electricity retailers will be required to surrender the appropriate number of certificates to the Office of the Renewable Energy Regulator (ORER), or pay a fine of US$19.8 for each missing certificate. Certificates can be traded independently of the electricity market, either bilaterally or through a multilateral ‘green energy market’ that went into operation in June 2001.

The market in renewable energy certificates (RECs) will be a big benefit to potential renewable energy suppliers, Rossiter claims, because it offers a second income stream to those seeking financing. ‘I have been careful to ensure that RECs are well-defined as property and meet international standards for commodities so they can be traded,’ he says. ‘When a project, such as a wind farm, is looking for financing, a bank will ask about forward cash flow. The project will now have cash flows for two commodities – electricity and RECs – so financing becomes cheaper.’ Rossiter notes that since the RECs are not tax-deductible, companies are effectively paying a fine of US$28 for each missing renewable MWh.

RECs are already trading at around US$12.4/MWh, according to Rossiter, and he expects the price to go up as the end of the financial year approaches and RECs must be surrendered to ORER.

The REC scheme will provide a new income stream – up to US$28/MWh – for Hydro Tasmania’s wind power projects. ‘We expect the construction cost will comes down anyway,’ says Gill, ‘but the REC is the first such market-based scheme in operation and it is bankable enough to make wind energy viable.’

An opportunity to uprate

Small hydro schemes and upgrades to large hydro plants will both qualify as renewable energy suppliers under ORER’s rules – setting an important precedent for similar renewable energy requirement schemes at various stages of development overseas. For Hydro Tasmania, this is an opportunity to invest in uprating its existing units.

‘It is bankable for any additional hydro energy above a regulated baseline, if we can uprate we can get both the additional energy and the RECs,’ Gill notes.

The oldest of Hydro Tasmania’s plant dates back to the early 1900s, and as many as 11of its plants could produce more power. It is a source that the business is keen to exploit. As Gill explains: ‘Our aim is to progressively review the upgrade potential of the turbines. Hydro Tasmania expects to achieve a 1.5% increase in average annual energy production – and with the RECs this could become a commercial opportunity. Alternatively we hope that we may be able to design the turbines for enhanced peaking power.’
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Renewable energy requirements…

Australia’s new renewable energy requirement, and the income stream generated from Renewable Energy Certificates, may be important for the future of the Snowy scheme, which has come under both commercial and environment pressure in recent years.
A campaign to revive flows in the original rivers that feed the Snowy system resulted last year in a decision by the Victoria, New South Wales and Federal governments to restore part of the original flow. Under the Heads of Agreement, signed in 2000, it was agreed to restore 21% of the original flow within ten years, and later to increase the restoration to 28% of the original flow. The intention was to ‘improve the temperature of the river, achieve better channel maintenance and flushing flows, restore connectivity for migrating species and dispersion, improve triggers for fish spawning and improve the river’s aesthetics’. Flow in the Murray river must also be maintained. The new flows were to be provided from storage for the first three years, following which time they are to be sourced from altered flows at Jindabyne.
The change is to be supported by government grants totalling US$74.2M from New South Wales, US$174.2M from Victoria and US$37.1M from the federal government, to compensate for what is estimated to be 150GWh/year in foregone electricity generation. But that support will last for only the first ten years of the revised flown pattern.
Responses from the Snowy scheme to this decision are limited at present as the organisation is in the throes of a ‘corporatisation’ which will see it operate as a more commercial entity within the National Electricity Market. It is unwilling to discuss issues that relate to future profitability, although according to Renewable Energy Regulator David Rossiter the result of the successful campaign to ‘let the Snowy run free’ will be a 10% loss to its capacity. But Rossiter was positive about the system’s future profitability.
The Snowy River hydro stations have considerable potential capacity for uprating, he said, even with altered flows. And although renewable energy qualifies for certificates only if it is over and above 1997 capacity, Snowy upgrades will not have to ‘catch up’ to the scheme’s original capacity before it can take advantage of the new income stream. Rossiter says that, uniquely, ‘ORER will reset Snowy’s baseline capacity’.