The generation game_3

15 October 2003
More news

16 October 2003

When the lights went out across swathes of the US, Canada and Italy, people asked whether the UK was also vulnerable to widespread blackouts. Scott Dendy explains what regulators, users and suppliers are doing to prevent them

Things are changing in the power market. After a couple of years of falling prices, the wholesale market is firming, and quickly. This shift is largely in response to fears of a shortage of generating capacity as peak demand this winter is forecast to come close to the maximum output of the UK's power stations. The recent blackouts in London and Birmingham have helped to stir things further, to the point that energy buyers now face an unenviable challenge to secure value.

Blackouts aside, for the moment the real issue here is not the ability of National Grid Transco (NGT), which operates the transmission grid, to deliver power - it's more the actual amount of power available against the level of demand.

For the past two years, since the introduction of the new trading rules (known as the New Electricity Trading Arrangements, or Neta), the wholesale price of power has fallen dramatically, by around 40 per cent.

However, it is all too easy to get used to low prices and start to see them as the norm. Could this be about to happen in the power market? Well, all of the signs appear to be pointing in that direction.

The problem starts with oversupply. For a while, there were simply too many power stations. The deregulation of the market in 1990 and soft gas prices led to a massive move to build state-of-the-art gas-fired power stations (using combined cycle gas turbine technology, or CCGT). But the economic downturn followed by the power price collapse put an end to the so-called "dash for gas".

The power cut in London was a great inconvenience, but it was not as catastrophic a failure as the earlier blackout in the US, which left much of New York State and a large part of Canada without power for a number of days, and the more recent cuts in Italy that affected the entire country. As soon the US blackout happened, the question was being asked "Could it happen here?" So when London did lose power for 35 minutes a few days later on 28 August, the doommongers were already crowing "told you so". However, what must be made clear are the stark differences in the networks and operation of the UK and North America.

The US and Italian blackouts exposed a serious weakness in the interconnected nature of their grids. In Italy, a transmission line taking power over the Alps from Switzerland to Italy was struck by a tree, causing other lines to overload and leaving almost the entire country without power.

By contrast, the London power cut was the result of human error and bad luck. It was alleged that the blackouts were a result of privatisation and underinvestment. This seems unwarranted as NGT has increased investment in its network substantially, to £3.6 billion since 1990 on its network - four times as much as was spent in the 1980s.

The problem with the London power cut was human error, the wrong piece of monitoring equipment being used and the fact that this was not picked up by checks. Working practices may have been at fault, but these can be identified and improved.

Bad luck prevailed in London, not only because two separate failures happened at the same time, but also because it followed the North American incident and happened in the "soft news" month of August.

Not guaranteed Where does this leave the customer? The standard connection agreement carries an ominous clause: "We do not guarantee that we will deliver electricity through our network at all times or that electricity delivered through our network will be free of brief variations in voltage or frequency."

Under the Utilities Act 2000, distribution companies, which take the power off the grid on to the lower voltage networks and then in to premises, have immunity against being held liable for economic loss caused by power failures. Where a company suffers a series of interruptions, it can make a claim, but this may only come to around £100 after four or more interruptions over a year.

In reality, the only option for avoiding lengthy power cuts is to install on-site generation. This can be expensive and should only be pursued if the economic risks of power loss outweigh the costs associated with the acquisition and maintenance of generating equipment.

The real issue in the power market today is the slow but enduring growth in demand versus the rate of new capacity coming on stream to meet it. The recent lending fiasco in the generation end of the market has left few banks prepared to hand over the cash for new projects: they got burnt after wholesale prices collapsed and few of the new market entrants could return their borrowing for generation assets.

Whereas in the past, the focus for meeting demand has always been on building new power stations, the banks' reluctance to make the same mistakes again meant that new solutions have to be found.

This is where the demand side comes in. If you can't build the plant quickly or profitably enough (and the grid said it was 2GW short of the spare capacity it wanted this summer), the obvious next move is to consume less at periods of peak demand. However, this is no simple task and needs co-ordination and adequate rewards.

The idea is being supported by the Energy Intensive Users Group (EIUG), a lobby group for big industrial energy users. Jeremy Nicholson, its policy adviser and spokesman, explains that the hype about London's blackouts distracted attention from some important and good work.

"NGT has taken the matter seriously and it is talking to the right people," he says. "It has the option of a large demand-side response, if the right incentives are in place."

One company at the forefront of such an approach is Gaz de France ESS's Special Market division. Originally part of Yorkshire Electricity, it was set up to help large consumers offer demand reductions into the electricity pool, Neta's predecessor.

Mark Bailey, director of special markets at GdF ESS, has been working with NGT over the summer to assist in finding short-term solutions to help reduce load in a period of an uncharacteristically tight capacity margins. The extreme hot weather increased air-conditioning demand just as a number of power stations were either being mothballed or undergoing maintenance, and the grid struggled to meet demand.

He says that GdF ESS "specialises in aggregating consumers interested in load reduction contracts [using less power] with the grid, allowing for payments to be made to users that could make controlled reductions in consumption on request. These are typically large end-users, but they could include large commercial chains."

GdF ESS offers a complete package whereby it will assess a site, install the necessary monitoring and switching equipment, and manage a site's power demand in accordance with the needs of NGT and contractual positions.

Under normal conditions, the grid offers "warming" and "hot" stand-by contracts with generators, to manage system security effectively. It requires a sufficient operating margin between generation and demand at a day-ahead and on-day stage. Demand-side customers have not previously been able to operate in these markets, although this has been changing since the summer.

One of the main thrusts behind this development is coming from the newly formed demand-side working group, chaired by industry regulator Ofgem. It is made up of industry lobby groups such as the EIUG and the Major Energy Users' Council, as well as NGT and an assortment of other interested parties.

Despite its relatively low profile, the group has great potential for helping to balance supply and demand. The market does not look ready to support more dedicated, and expensive, generation used only a few times a year in peak demand periods. What would be better, it is argued, is to use the ability of large end-users to come off-stream when it is more cost-effective to do so.

More formal options have been, and will be, developed to help meet the challenges of the coming winter when demand is at its highest. Expect more "turndown contracts" (in which users agree to have their power cut by a specified amount at short notice) to be offered over the coming months.

GdF worked fast with NGT and energy users on an ad hoc solution to use less power - with the help of smaller consumers than would usually be practical - when the grid issued a notice of insufficient margin on 14 July. Within a week, consumers had handed 70MW to NGT. It may not sound like much, but 50MW could be the difference between uninterrupted power and a blackout.

The grid has traditionally looked at supply and demand in large lumps of 50-100MW. What aggregators like GdF are offering to do is build portfolios of a size that NGT can use, by pulling together a number of different sites with capacities of roughly 1MW and above.

"We are now working with customers and NGT to develop a suitable product that meets their 100MW, data monitoring and core administration criteria for Turndown. The necessary 100MW blocks can be managed by us through aggregation, while our settlement data, on-site systems and real-time metering could all be used to meet the metering requirements."

Shedding their load For many consumers, the opportunity to engage in load-shedding contracts may not be suitable, whether because of their relatively small scale or their uncontrollable load. For these customers, price will remain the main concern. And fears of tightening capacity margins and blackouts have led to some dramatic pricing activity. Once again, price uncertainty has been prevalent going into October's round of tenders, which is traditionally a busy time in the sector.

According to energy specialists John Hall Associates (JHA), customers going out to market now for annual contracts can expect to see some pretty hefty increases. With preliminary results just in from the latest tender round, the consultancy has noticed average increases of more than 12 per cent for just the energy component of bills (the rest is made up of transmission costs and supplier's margins). For all-inclusive contracts (which include all of the transportation and fixed elements of the bill), the average rise was about 8.5 per cent.

When the renewables obligation (a punitive scheme designed to help pay for the government's ambitious target for renewable energy growth) was factored in, JHA said that some energy component-based contracts could be about 23 per cent higher than last year.

These are serious price increases and could have a significant impact on some businesses' profitability. But are these prices justified? On the face of it, yes. These end-user prices are a direct response to activity in the wholesale market, which rocketed over the summer.

But has the wholesale market moved on fear rather than fundamentals? That is not clear and, like any commodity market, uncertainty builds volatility. With the penalty so high for getting it "wrong" in the electricity forward markets, this market tends to price uncertainty (especially that associated with tight capacity) at a considerable premium.

This uncertainly was borne out during the tender round. As prices constantly moved upwards, offers' shelf-lives kept shortening, with offers frequently removed or updated. JHA notes that the time offers were available and had to be accepted by had been severely reduced, moving the timescale closer to that of the gas industry - one or two days. This is a telling sign of how far the market has moved since competition was introduced and is also a feature of the increased market risk that suppliers face since Neta's launch.

Prices may not settle until after the winter, should NGT prove it can balance demand with supply effectively and keep the lights on. If that happens, prices may soon soften. Should something go wrong, the market can expect some rather volatile and spiky pricing resulting in further price increases during the next significant tender round in April.

The likelihood, however, is that the lights will stay on and prices will stabilise, albeit at a higher level than in the past couple of years.

Despite the upwards shift in prices, the EIUG's Jeremy Nicholson is not too alarmed. "After years of campaigning for a market at the centre of energy pricing, it would be somewhat unreasonable for us to moan as soon as it is implemented and prices move against our members," he says.

"If prices had remained that soft, it would have created problems in the future owing to lack of investment, and that would not be in the long-term interest of our members. What we will be looking out for is that any price rises are justifiable and that suppliers do not attempt to exploit market uncertainty unfairly for their own gain."

Nicholson believes that some price adjustment is necessary to secure the long-term future of sustainable energy supplies, and that prices are now approaching a level that should offer the right signals to deliver this. Getting the balance between providing a fair return for generators and providing investment signals in an industry that has long lead times for things such as new power station construction is essential. Neta has not been going for long enough to know if these signals are truly coming through in the predictable and organised fashion needed.

This winter will provide the litmus test. Early indications are that, whatever the government is doing, the market is preparing itself to keep the lights on.

• Scott Dendy is editor of UK Powerfocus. For more information, visit www.ukpowerfocus.com, or e-mail scott.dendy@mccloskeycoal.com

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