A report by the International Energy Agency (IEA) published on October 30 could not be more enthusiastic in its praise of the UK's energy policy. The IEA enthuses that the UK's ?pioneering role in energy market reform has allowed it to reap the benefits of free and open markets.? UK consumers would certainly not dispute that and the introduction of the NETA system has achieved exactly what it set out to do ? retail prices have dropped 30% since 1990 and the market is now truly competitive. But the report will make bitter reading for many investors who have financed this transition and are now on the receiving end of its establishment. ?Such price changes affect the financial viability of existing and new generating capacity of all kinds,? notes the IEA, in what many will see as something of an understatement.

The problems for banks exposed to the sector boil down to one thing: overcapacity. There is calculated to be roughly 22% overcapacity in the UK generating sector and it is therefore not surprising that prices have slumped so spectacularly. Prices are now around £17 to £18 per MW/hour, down 40% from their levels prior to NETA's introduction as generators, desperate to avoid mothballing capacity, have continued to run their operations in a negative spark spread environment. There are now growing calls for forced closures of capacity in order to enable prices to recover to a level at which power generation can become a viable activity for IPPs. At the end of October, the Institute of Public Policy Research called for incentives to be offered for some of the country's 6GW of coal-fired capacity to be shut down in order for more efficient gas-fired capacity to survive. And Powergen chairman Ed Wallis has told the Department of Trade and Industry that the only route out of the mess is for a dramatic cut in the number of coal and oil-fired power stations. Powergen mothballed a quarter of its generating capacity in October.

Who's in trouble?

The roll call of UK power generating companies that have run into trouble as a result of the situation is a graphic illustration of the importance of vertical integration in this industry. Wholesale prices may be down 40% since NETA was introduced but retail prices certainly are not. British Energy, with its eight nuclear plants and one coal-fired plant at Eggborough in North Yorkshire, has been the most spectacular casualty of the price slump. The company has continued to operate thanks solely to an emergency £650 million ($1 billion) bail-out from the UK government. Eggborough is, however, ring-fenced from the rest of the group and not covered by the government loan. Its problems have been exacerbated by the fact that it is a pure generator with no retail supply business to make up the losses that it has incurred in generation. This is the problem facing another pure generator, AES Drax, which operates a 3960MW coal-fired plant in North Yorkshire ? the largest coal-fired plant in Europe. But Drax's current problems are also the result of a £20 million default by the distributor to which it sells roughly half of its output: TXU Europe. The latter has suffered from the withdrawal from Europe of its US parent, calling into question the financial viability of all the power plants with which it has tolling contracts ? not only Drax but others such as Rugeley which International Power acquired from TXU. TXU Europe has, however, issued a notice of termination of its 15-year contract with Drax on November 8, citing Drax's failure to provide a £50 million letter of credit. This notice lasts for 90 days. The company is now trying to reach a settlement on five long-term power purchase contracts in total.

But the difficulties in the market are by no means universal. Vertically integrated players such as Innogy, Powergen, Scottish Power and Scottish and Southern can all take advantage of the increased margins on the retail supply side made possible by the drop in wholesale prices. Thus, although they may be facing problems on the generation side they are far better placed to survive in the current climate.

Eggborough, Drax and Rugeley are certainly not the only plants to have been affected. The 360MW Fifoots Point plant, also operated by AES, has gone into administration and NRG Energy is in negotiation with banks over the prospects for a dividend payment on the Killingholme CCGT plant. That plant was financed via a loan arranged by Bank of America. The collapse of Enron was responsible for pushing the Enron group-operated 1.9 GW Teeside plant into receivership. It has subsequently been bought out by management.

How much trouble are they in?

Clearly each project faces its own individual set of problems but the root cause of the situation is wholesale prices. The question remains, however: should the lending banks have foreseen the impact of NETA? And could the deals have been structured differently in order to protect against the impact of the widely anticipated price slump?

The Drax plant was acquired by AES in 1999 via a £1.725 million eurobond. This facility was subsequently refinanced via a £1.3 billion loan, £250 million subordinated bridge facility and £425 million equity. The loan was lead arranged by Chase, Deutsche Bank and IBJ. Eight banks signed up as co-arrangers: Abbey National, Bank of Scotland, BoTM, Bankgesellschaft Berlin, Fortis Bank, MeesPierson, HSBC, National Australia Bank and Rabobank. The deal was structured as a 15-year amortising term loan with pricing ranging from 165 bp over Libor to 180bp over Libor. The $250 million bridge loan was provided by Goldman Sachs and Donaldson Lufkin &Jenrette. At the time, Standard & Poor's highlighted the uncertainty surrounding generation prices as a concern but stated that one of the deal's strengths was its 15-year financial hedging agreement with Eastern Energy (subsequently TXU Energy) ? which is now on notice to be terminated from February 3, 2003. ?[The hedging agreement] underpins a large portion of the debt service during the first seven years of the contract thereby reducing merchant risk? the agency said. Could ? should ? the banks have foreseen that their investment-grade hedging counterparty would be technically insolvent a mere three years later?

The crisis at TXU Europe was triggered by its US parent withholding a $700 million payment to its European subsidiary prompting the latter to default of a £20 million payment to Drax. As a result TXU Europe bonds were downgraded to junk and NM Rothschild was appointed to find a buyer for the European business, which was swiftly sold in late October to rival Powergen for £1.62 billion in cash and assumed debt. The problems at the company were compounded by the fact that it had lost around one million of its customers (the vital ingredient in protecting against the impact of low wholesale prices) to Centrica. Bankers close to TXU Europe have expressed disbelief at its parent's actions, saying that they had received assurances of support and that TXU Inc had recently invested £350 million in TXU Europe in order to allow it to acquire new businesses in the region. TXU Europe is being advised by NM Rothschild, Herbert Smith and Ernst & Young. ?At the time this deal was done the banks assumed that the US parent would be behind its European offshoot,? notes one banker close to the sector. ?Maybe the banks could have done more to demand a guarantee from TXU in the US but Eastern Electricity was a regulated business.?

Could the price slump have been predicted?

The question of whether the impact of NETA could have been anticipated is a contentious one. ?The deterioration in the market was unpredicted and is almost irrational,? says Richard Burrett, managing director and global head of project finance at ABN Amro. ?Would the banks have run sensitivity analyses at this low level of price generation? Yes. Would they have predicted negative spark spreads to be sustained into the medium term? No.? There is certainly no doubt that price falls were clearly anticipated following events following deregulation of the energy markets in Norway and Australia but it seems that the speed with which they fell caught all concerned wrong-footed. It is simply not the case that if the arrangers had been more cautious and put shorter tenors and faster repayment schedules into these loans that the situation would have been any different. ?This has gone further than anyone predicted,? says Chetan Modi at Moody's in London. ?The atomisation of the generation sector was a function of new entrants and forced sales and in reality pricing power was lost in this market before NETA was introduced,? he says. ?But nobody's worst case scenario foresaw this.? Jan Willem Plantagie, credit analyst at Standard and Poors in London, agrees that the timing caught everyone by surprise but emphasises that the rating agency took a cautious view. ?S&P estimated that actual prices would fall somewhere between the low and collapse case and would fall to below £18 MW/hour by 2004 to 2005. The bank base case scenario took the view that this would not happen at all. In actuality it happened in 2001. These price levels were anticipated but the speed with which it happened has taken everyone by surprise.?

The introduction of NETA necessitated a renegotiation of the offtake agreements between the generators and distributors ? a source of some conflict at the time. Under the old pool system generators would hedge against price volatility through contracts for differences referencing the universal pool price but under NETA the two parties have to agree between themselves on a price. Distributors, generators and their suppliers all agreed long-term power purchase and tolling agreements that are now clearly well out-of-the-money as wholesale prices have fallen so far so fast. UK Coal has a £755 million contract to sell coal to TXU Europe fixed until 2010 and a £700 million five-year contract to supply Drax with 25.5 million tonnes of coal. UK Coal is now owed £15 million under the contract. UK Coal also has a £150 million contract with British Energy to supply coal to Eggborough. Britsh Energy has defaulted on around £75 million in payments to British Nuclear Fuels (BNFL) which supplies its plants but has agreed to make up its missed payments in order to avoid a threatened lawsuit.

Debt mountain

By committing themselves to long-term supply contracts and underestimating wholesale price falls these non-integrated generating companies now face serious problems. The question for their banks and bondholders is how much, if anything, can be salvaged from the wreckage. As at March 2002 British Energy's total financial debt included three sterling bonds totalling £408 million, a £508 million loan to finance the Eggborough acquisition and around £110 million deferred payments by US subsidiary Bruce Power. The Eggborough acquisition refinancing was arranged by Barclays Capital in the form of a 90% leveraged £508 million loan with a tenor of 15 years. It was put together at the end of 2000. This refinancing enabled British Energy to take the deal off-balance sheet. It had previously been financed via a £350 million and £250 million revolver lead managed by Deutsche Bank. The Eggborough loan is non-recourse to British Energy but BE has given a guarantee to Eggborough Power for the payment obligations of its trading subsidiary ? which may be a source of some comfort to lenders. BE was, however, forced to write down its Eggborough investment by £300 million last year and increased its provisions in respect of long-term trading contracts by £209 million to £344 million. On November 5 shareholders approved an increase in the company's borrowing limits to £1.6 billion (from £1.1 billion). The government's £650 million bailout is due to expire on November 29 but it is likely to be extended beyond that while a solution is thrashed out with the UK government. SSSB and Lazard are advising BE in the negotiations and CSFB is advising the government. In early November the market was gripped by news that some distributors, Innogy among them, had approached the government with a proposal to buy electricity from British Energy at a price above current market rates in order to try to keep the generator going. This was, however, swiftly denied by Innogy's chief executive, Brian Count.

Within TXU those with exposure to TXU PLC seem to have a better chance of recouping funds than those exposed to TXU Ltd. ?TXU Europe Group PLC creditors are lower down the structure and therefore closer to the assets,? explains Modi at Moody's. ?They are likely to have priority over the creditors of TXU Europe Ltd.? In Modi's view TXU Europe Group PLC creditors may not be that badly affected. ?The exact position has still to be determined but the assets at TXU Europe Group PLC might broadly cover its debt,? he reckons. TXU Europe Group PLC includes lenders to TXU Eastern Funding and The Energy Group.

TXU Europe Ltd creditors' prospects for debt recovery are further reduced by the fact that the company is guarantor under its power purchase contracts with Drax (AES) and Rugeley (International Power) and Scottish and Southern Energy. Drax sells around 60 % of its output to TXU Europe and Scottish and Southern and International Power sell about 10% of their output to the company. These contracts are now significantly out-of-the-money but it has not been confirmed by how much. Standard & Poor's estimates that the range of possible outcomes for the present value of the out-of-the-money component of the contracts is between £500 million and £1.3 billion. In an insolvency situation these power purchase contracts are structurally senior to the TXU Europe debt and therefore would rank ahead.

Modi estimates that Drax would have a claim of around £270 million against TXU should Drax terminate the contract that TXU Europe has now issued notice on. An important difference between the two is that Drax is not hampered by TXU Europe's 90-day notice period. If it decided to counter-terminate the contract it could do so with immediate effect. This was a provision that the banks insisted on when the Drax financing was done. ? Drax is now attempting to reach a negotiated settlement with TXU Europe as it wants to avoid claiming against TXU Europe when it [TXU Europe] is in administration,? says Modi. ?But now that this notice of termination has been issued it is only a matter of time before Drax fails,? he adds.

Not great news for the banks and bondholders. Drax's current outstanding senior bank debt amounts to £843 million, amortising until 2015. It has $302.4 million bonds due 2020 (for which amortisation begins December 31 2015) and £200 million bonds due 2025. The next interest payment is due on December 31 this year and amounts to around £18 million. It also is due to make £15 million semi-annual interest payments on the subordinated notes until 2010. This prompts the question of what could be raised by a disposal ? but what is 4,000MW of capacity worth? A rough guide may have been provided by the Eggborough write-down which valued each kW of capacity at around £150 (Thus the 2000MW station was valued at around £300 million). By the same very inexact yardstick Drax's 4000MW may be worth £600 million.

How accurate this assessment is may soon become clear with the news over the weekend of November 9 that German-owned Innogy has appointed SSSB to advise on a £1 billion bid to buy the power plant back from AES. Innogy (in its previous incarnation as National Power) sold Drax to AES in 1999 for £1.87 billion. In what will be adding insult to injury for AES, Innogy is likely to have to pay a fraction of that price to get the plant back. Not surprisingly, Innogy has lobbied the High Court in London to push TXU Europe into administration ? a move that will force a Drax sale.

Chetan Modi at Moody's reckons that if TXU's contract with the Rugeley plant was terminated under some NPV-type calculation payout it is possible that lenders could be repaid in full, subject to assets at TXU Europe Group PLC covering the liabilities. Moody's changed its outlook on International Power from positive to stable but kept its Ba3 senior rating as a result of events at TXU Europe. IP has an investment of £56 million in the Rugeley project and is thought unlikely to inject any further capital to support the project financing. The loan took the form of an £190 million off-balance sheet loan with a tenor of seven years arranged by ING and TD Securities in 2001 together with BTM and Credit Lyonnais.

Bond versus bank

The situation in the UK power sector has again raised the debate about the relative merits of bond versus bank finance in a distressed situation. The Drax power plant project is the only one in the UK to have used bond financing. ?There is some truth in the argument that bank financing is better in a distressed scenario,? says Bruce Johnston at law firm LeBoeuf, Lamb, Greene & McRae in London. ?Bondholders tend to have a short-term mentality.? The effects of this have been seen in the US market where a far greater proportion of power projects have been funded in the bond market. As these bonds have been downgraded ? often to junk ? many institutions are not longer permitted to hold them so there have been large volumes of paper changing hands. ?The more bond debt that you have the more unpredictable things are going to be in a bankruptcy,? agrees Burrett at ABN Amro. ?When a project is fully bank funded the banks historically can get together as a group in order to work out a solution.? Where there are a large number of bondholders this becomes increasingly difficult to orchestrate. The disruptive influence of hedge/vulture funds trying to take advantage of the bankruptcy can also be a major factor mitigating against a restructuring in a bond-financed situation. But Johnston points out that the advantage of a bank syndicate should not be overstated. ?The banks can get together and form all the steering committees they like but if there is no money coming into the project there is really very little that they can do,? he says.

In TXU Europe's case it is a feature of its bond debt ? rating triggers ? that has been a focus of criticism. Rating triggers have been far more widely used in energy, power and utilities sector bond issues than they have in other sectors such as food and retail. They are designed to offer investors protection but are now being questioned throughout the market. Once TXU Europe was downgraded to non-investment grade five separate rating triggers were breached, putting liquidity calls on the company that it could not meet. ?If TXU Europe had not had the rating triggers that it did then it would not be in its current position,? reckons Modi. ?Triggers are a liquidity issue. If there is a finite amount of liquidity available then a company with triggers is a weaker credit than one without. Many issuers are now far more aware of the potential impact of triggers and there appears to be greater reluctance to use them,? he says. While no-one is blaming triggers for TXU Europe's predicament, it seems likely that without them it would be in better shape than it is at the moment and it is a situation that was almost waiting to happen. ?Triggers are now being removed from many transactions in the US,? notes Burrett. ?The problem is the ?house of cards' effect that they potentially create.?

Sitting it out?

So what happens next? Many people have drawn parallels with the telecoms sector but there are fundamental differences. For lenders to telecoms projects it was a question of estimating how much the market was likely to grow. For power projects there was an existing market and everyone knew that prices were likely to fall. ?What people failed to appreciate was that prices would fall to a level that is patently uneconomic for everyone involved and stay there,? observes Burrett. ?A lot of artificial protections [such as the government's inevitable support for British Energy] have been put into the market that have meant economic logic being thrown out of the window.? One more appropriate precedent could be Eurotunnel and it may therefore a question of how long the banks are prepared to sit it out until things get better.

?Banks have a hope value attached to their exposure,? says Johnston at Leboeuf. ?They will be hoping that things may improve once the situation at British Energy is resolved and has worked its way through the system.? It is not surprising that the likes of Powergen are calling for BE to be put into administration as it would be a step closer to what everyone wants: a culling of capacity. Powergen's German parent E.On is expected to have to write down around Eu2 billion on its Powergen investment by the end of the year partly as a result of capacity outages.

Various rumours have emerged in the market surrounding what action might be taken to cut output. One suggestion is for all the affected banks to get together to effectively form one mini-generating company but this is highly unlikely as there are too many banks with too many conflicting interests. But some feel that projects could in some way group together to support each other in the short-term. ?If eight plants could group together it would make it a lot easier to turn off one plant and have the pain shared by the other seven,? suggests one market participant. But if the situation continues in the current vein it will become more and more tempting to just walk away.

Trying to de-leverage the projects could eventually lead to debt for equity swaps as was the case with Eurotunnel. But the banks are unlikely to want to hold equity and this can lead to regulatory conflicts of interest for the banks. ?The banks may eventually start selling to vulture funds,? notes Johnston. ?But once there are financial institutions out there buying you know that prices are already too low,? he observes. As well as being bleak for the projects involved the situation does not bode well for future lending to the sector. Margins in the US have gone up by 25bp to 50bp and the same can be expected in Europe along with greater difficulties in distributing deals as credit committees clamp down on power exposure.

?There are three levels of concern among the banks,? says Richard Burrett at ABN Amro. ?Firstly they are now highly reluctant to take merchant risk of any kind and not just in the UK. Secondly they are very sceptical about long-term power purchase or tolling contracts that are in any way considered out-of-the-money or are likely to go out-of-the-money and thirdly some banks are simply saying that power is off the agenda for the time being.? It is easy to be wise after the event but some in the market feel that the banks involved in these deals are to some extent architects of their own situation. ?Banks sometimes simply underestimated the risks involved,? says Jan Willem Plantagie at S&P. ?Merchant risk is usually BB risk (non investment grade) at most unless it benefits from a very conservative finance structure. Maybe people will now start to assess and price risk properly. This is what happened in the US after Enron ? people went back to focus on true project risk analysis.?

In some quarters, sympathy for those caught in this pricing trap is in short supply. ?In reality the UK power market isn't nearly as tough as its participants would have us think,? says John Lane, senior utilities analyst at London-based Datamonitor in a report. ?The residential supply sector in particular remains a cash cow. Credit should be given to the regulator for standing firm in the face of all this criticism and stating the case that competitive markets are tough and do produce winners and losers.?