NETA (New Electricity Trading Arrangements), the UK's controversial new wholesale electricity market, was finally launched on March 27 after a series of delays. The new system, which exposes generators to direct trading risks, is one of the most far-reaching reforms of any electricity trading market in the world and as such has attracted its fair share of criticism and praise.

The system was implemented with the political objective of reducing the cost of wholesale power and therefore reducing the cost of power to the consumer. It is far to early to tell whether this objective will be achieved and the first few weeks of the system have been characterised by huge price spikes and technical glitches.

It could be a year before NETA is running smoothly, but when it does the market will be more competitive and prices will come down. As radical a change as this will also have a marked impact on the Independent Power Producer (IPP) project financings that have been drawn up in the UK over the last decade as the technicalities of the way in which their power is sold are changed and they address the prospect of a substantial drop in revenues.

Despite NETA's teething problems, there is no doubt that the UK's previous system of energy trading was sorely in need of revision. ?Changes were clearly needed due to the failure of the pool to respond to price changes,? says Nigel Knee, market development manager at British Energy, a UK-based IPP. ?Price became very clearly split between generation and supply. There were also problems with capacity.? The way the old system worked was that generators bid into the electricity pool in half-hourly segments.

Generation was then brought on-stream on the basis of lowest price first. Pool customers were, however, charged for on the basis of the highest price bid (the marginal cost, which set the offtake price), with the balance used to cover the costs of running and developing the system. The system clearly maintained the offtake price at a high level and also was wide open to manipulation by the generators, which could withdraw capacity to keep prices high.

The new system, NETA, involves the replacement of the electricity pool with a series of bilateral contracts between generators and purchasers. Thus, instead of just selling into the pool, generators will now actually have to go out and find customers. A short term balancing mechanism, known as the UK power exchange, sets the price for anything from two days' ahead to 4 hours ahead. This effectively works along similar lines to the old pool, but the off-take price is based on the actual price bid rather than the marginal price. Participation in this balancing mechanism is, also, optional.

The system should lead to lower electricity prices for the consumer and in other regions where similar systems have been implemented (such as Scandinavia and Australia) this has indeed been the case. The new system exposes generators to dispatch risk, whereby they risk generating power they cannot sell, or not being available to generate power that they have contracted when it is needed. This risk was previously assumed by the system operator under the electricity pool arrangements. There is some potential to mitigate this risk through the physical delivery contracts but it represents a significant change in trading arrangements for the generators. NETA participants are also now directly exposed to counter-party settlement risk.

?We were never convinced that OFGEM has made a case that the kind of changes that it was proposing were justified,? says Knee at British Energy. ?But now it is important to make these changes work within a very demanding time scale.? NETA, which has been three years in development and has cost around £1 billion to implement, was originally due to go live in the third quarter of 2000 but was delayed due to technical problems. OFGEM and the DTI were determined that the March 2001 deadline would not be missed and the system has suffered from a number of technical problems since launch.

NETA services are managed by quasi-independent balancing and settlement company Elexon and prices are posted on the balancing mechanism website, BMReports.com, which is operated by a consortium headed up by Logica. Since launch the system has been hampered by several prices being posted incorrectly on the site. OFGEM declined to talk to Project Finance for this article but according to Sally Fishleigh, communications manager at Elexon ?There is no problem in the calculation of the price, just in how it gets displayed on the site?. She emphasises that the problem was known prior to the system going live. Elexon is now having to post a daily circular on its own website, Elexon.co.uk, correcting all the prices that appear incorrectly on the BMReports.com website.

The problems are caused by prices defaulting when certain conditions apply, for example when no bids or offers have been accepted during a certain period or when accepted bids and offers are arbitrage tagged out of the system during that period. The results can, however, be extreme. On the first day of trading, prices quoted for a typical £20 unit varied from as high as £32,000 to as low as negative £200, even hitting the limits of £99,999 and negative £9,999. ?The shortcomings of the system are now becoming apparent and it is clear that insufficient modelling was done and they simply ran out of time ? this is a very complex piece of software,? notes an executive at one UK IPP.

. Knee explains that there has also had to be emergency changes to the rules that govern cash-out prices due to the huge variations in price that are occurring. ?There is still a lot of volatility in the balancing mechanism, particularly between top-up and spill prices, which means there is a very sharp incentive to balance before closure each day,? says Knee.

Once the system is closed at commencement of the last four hours of the day parties are exposed to price risks that they can do nothing about.

Although there is a degree of frustration with NETA's teething problems, most generators welcome the shake-up to the way they sell their power. ?NETA is good for merchant generators ? despite the fact that there have been some wrinkles in the system,? says a spokesperson for International Power, formed from the splitting of National Power last October. International Power has just one IPP plant in the UK, the 500MW Combined Cycle Gas Turbine (CCGT) plant at Teeside. This plant is around seven years old, and is less exposed to NETA than some others as the majority of its output is contracted to one buyer. 97.5% of the Teeside output is contracted to Innogy which took the remainder of National Power's UK plants when the firm was split. But the impact of NETA on the contractual arrangements between generator and power purchaser is proving to be a headache for some IPPs ? particularly those where contracts were drawn up long before NETA was ever proposed.

?IPPs now have to look at their existing contracts and decide whether they can work without the old pool arrangements,? explains Ian Jefferson, director in the project finance group at Barclays Capital in London. ?It is a question of rejigging the terminology of the power pool as there is no universal price,? he says. ?There is a spectrum of situations from one IPP to another but all contracts will have to be altered to reflect the mechanical reality of NETA.?

The contractual arrangement that is most sharply affected by this is the swap arrangement between generators and off-take counter-parties designed to hedge against volatility in the pool price ? known as contracts-for-differences (CFDs). These contracts are now effectively invalid as there is no longer a pool price. ?Under the old pool system you could hedge price risk with payments being required to be made either way [by the generator or the offtake party],? says John Storey, assistant director is the portfolio management division of the project finance group at RBS NatWest in London. NETA has scrapped that and the parties will now have to come together to renegotiate, and not all will have made provisions for what to do in the situation that they cannot agree.?

Such a situation arose between AES as generator and TXU as off-take counter-party on power from AES's 4GW coal-fired Drax plant sited in the north of the country. Amendments to the two parties' 15-year hedging agreement were necessary under NETA and the two parties fundamentally disagreed on an index price. In this situation the disagreement usually has to be referred to a third-party expert panel, a move that both parties' to the contract should be anxious to avoid.

Knee at British Energy explains that there are generally two options open to IPPs in renegotiating their CFD hedging contracts. ?In the past people hedged because of pool uncertainty. Now that there is a physical bilateral contract under NETA there is essentially no longer a need to hedge,? he explains. ?But you still need to manage the risks of variations in price during the day.?

One option is to maintain the CFDs as financial derivatives and just apply them to a new reference price. This could be the price from the short-term mini-pool, the balancing mechanism. But whereas the old reference price took account of the price of providing electricity together with available capacity, this UK power exchange price does not really recognise the value of this capacity. The alternative is to agree a physical supply contract between the two parties and scrap the CFDs. The problem here is agreeing a strike price between the two parties ? and this is what AES and TXU could not agree on. In the Drax case, the financial hedging agreement has been temporarily reverted to a physical delivery contract. The parties have also agreed that the transmission charges payable by Drax will be shared 75% by Drax and 25% by TXU ? an outcome substantially in Drax's favour.

As a relatively recent deal, Drax was put together with NETA in mind. Paul Lund, utilities analyst at Standard and Poors in London, agrees that these issues could raise problems for older projects. But he does see some advantage for the older deals. ?The first generation of project-financed IPPs to use CCGT technology are in a better position than newer IPPs because they have long-term contracts in place to support debt service,? he says. There is a risk to some, particularly older, deals that the asset value of the project could be reduced to below its level of outstanding debt under NETA if the expected drop in expected generating output prices materialises. Another London-based analyst believes that this puts some IPPs at a distinct disadvantage. ?IPPs are in a much better position if they have a substantial portfolio of power plants than just one as they can spread their risk,? he says.

?A lot of IPPs have not even thought about energy trading and some plants have been very sluggish in addressing the impact of NETA,? says Jan Willem Plantagie at Standard and Poors. But even the most prepared plants can still have problems ? Drax is generally seen as an efficient plant with low marginal costs and one where contracts were drawn up in full anticipation of NETA. This did not, however, stop Moody's changing its ratings outlook on Drax from stable to negative following the changes to the hedging agreement. Moody's accepted that the impact on Drax cash flows of NETA is negligible but said that the new market structure had introduced a degree of uncertainty. Standard and Poors has maintained its stable rating outlook on the plant.

Although the Drax negotiations were decided very much to the generator's advantage, this does not mean that all IPPs can be sure that things will go their way. ?The few cases that I have seen have been fairly similar,? admits John Storey at RBS Nat West. ?But no expert is going to publicise their decision.?

RBS NatWest is an investor in another IPP project now addressing the CFD issue ? the Humber Power Project, a 750MW CCGT power station in Stallingsborough, Humberside. A consortium of banks financed this project in 1994 for a 2.5-year construction and 15-year post-completion term. What was then NatWest Markets was joined in the lead manager group by ABN Amro, CIBC and UBS. The Humber plant is now up for sale and three parties are understood to have been shortlisted.

Shareholders in the original deal included Midlands Electricity, Finland-based Imatran Voima Oy, ABB and Japan-based Tomen Corp.

British Energy has subsequently bought 12.5% of the project. Negotiations between the generator and the off-take counter-parties in this case are believed to be complicated by the fact that some of the off-take parties are shareholders themselves ? namely ABB and Tomen. ?The Humber situation is complicated by market uncertainty and the fact that the shareholders want to sell,? says one analyst.

It is rumoured that the situation has been referred to a third party expert. Neither Nigel Knee at British Energy or John Storey at RBS NatWest will comment on the situation at Humber.

?It has been questioned whether NETA is an occasion to review the whole power purchase agreement,? says Ian Jefferson at Barclays Capital. ?It is not.? But there is a risk to the physical performance of the project assets not least because of the anticipated price falls that NETA should deliver. IPPs with combined heat and power (CHP) plants will suffer under the new system as they have less ability to control the release of power into the system. NETA should signal the development of a true gas/power arbitrage as it will remove the huge discrepancy between power pool prices and gas prices. As a series of new CCGT plants has come onstream in the UK the percentage of electricity generated from gas has grown from zero in 1990 to 38% today.

Generators were previously locked into long-term, inflexible gas purchase contracts but can now arbitrage between the two by selling gas back into the gas market.

But NETA is being sold to the public as a means by which generators will be forced to lower their prices and compete for custom ? a politically popular move which explains why the government was so keen to push it through. ?The previous pool arrangement was deeply flawed,? says energy minister Peter Hain. ?It was effectively a means of generators setting a wholesale price which suppliers and large consumers had little choice but to accept.?