Coal is back - the UK Government's imposition of a gas-fired generation moratorium last year has shifted the landscape for the country's power market. No longer do gas-fired plants represent the overwhelming majority of the market.

"If you had asked me last year whether there would be so much coal-fired plant coming to market I would have said that it was extremely unlikely - as would have most people," says one head of power finance at a bank in London. "But this year we have seen a big turnaround in the market. If you totted up the amounts you would probably find more money raised for coal deals than for gas - a huge turn around for the market."

A quick look at the figures proves him right. Merchant coal-fired deals in 1999 have raised around £2.3 billion of bank debt. Until now, the entire gas-fired merchant power sector has raised roughly £1.4 billion through its seven transaction history, giving an average deal size of £200 million per merchant asset.

These figures are all the more remarkable given the generally held consensus has been that coal plants are not efficient enough to compete on a merchant basis with more heat efficient gas-fired generation.

But a number of factors have played in coal's favour. The chief issue has been that the government is keen to introduce greater competition for power pool prices. To this end, it wanted to reduce the generating capacity of both National Power and PowerGen. The resulting regulatory driven generating asset disposal of National Power's Drax coal-fired plant and PowerGen's Fiddler's Ferry and Ferrybridge plants provided the market with the opportunity to finance high-class, proven assets.

After strong bidding from some of the leading international power firms, AES Corporation won the right to acquire Drax and Edison Mission Energy was selected as the chosen bidder for PowerGen's assets. The two deals represented the first coal-fired plants with merchant risk to be financed in the UK and the size of the debt facilities for each of the acquisitions dwarfed all previous UK merchant power deals.

The larger of the two was the £1.87 billion paid by AES for Drax. The deal, which features a merchant tail, required some £1.325 billion of bank credits. Lead arrangers for the borrower were Chase Manhattan, Deutsche Bank and IBJ. The facility, which matures on March 20, 2015, is priced at a margin ranging from 160bp over Libor to 185bp. The arrangers sold the deal down to two sets of sub-underwriters before launching its retail phase. Both phases of sub-underwriting received a extremely positive responses from the market.

The second, and somewhat smaller, deal is the dual tranche £850 million limited-recourse financing for Edison Mission Energy, which raised the debt through special purpose vehicle UK Power Lending Ltd. The debt facilities are structured between two tranches - a £830 million term credit and a £20 million revolving credit. Pricing ranges from 160bp to 140bp. Both facilities carry a 13 year maximum maturity.

The borrower appointed a large group of arrangers on the deal and parceled out roles accordingly - Bank of Montreal (fuel), Banque Nationale de Paris (modelling), Barclays Capital (facility agent and documentation), Chase Manhattan (bookrunner and information memorandum), Credit Lyonnais (overall technical bank), Credit Suisse First Boston (facility agent and documentation), Dresdner Kleinwort Benson (insurance), SG (bookrunner and information memorandum) and WestLB (environmental).

Again the deal was extremely well backed by the market and in its sub-underwriting phase brought in a much bigger than expected number of banks. Both transactions are close to being wrapped up at time of press with all indications pointing towards a strong retail performance for both.

Bucking the trend

To put the stunning success of these deals into context, look back at the fortunes of a number of smaller gas-fired IPPs which were brought to market in the run up to the two acqiusition facilities.

By the time the last couple of gas-fired deals - notably the Greenwich NatWest arranged £200 million project financing for the Shoreham IPP, sponsored by Central & South West Corporation and Scottish Power and the SG arranged £250 million Great Yarmouth IPP backed by BP Amoco and Arco - were brought to market there was concern among project financiers and syndication specialists that the market's finite capacity to buy into these assets had already been taken up by the two merchant trailblazers of 1999: the £499.5 million Damhead Creek IPP arranged by Warburg Dillon Read and the £476 million InterGen-sponsored Coryton Energy project arranged by CSFB.

Both of these last deals were brought to market more or less simultaneously earlier this year in a curious parallel to the two acquisition facilities. Both managed to attract sufficient support from the market but not without a lot of work from the arrangers' syndications teams who were hard pressed to identify enough banks whose credit committees were able to be convinced to approve buying into a merchant power deal.

"The syndications of Coryton and Damhead Creek were both done in an environment with only a limited number of banks willing to take merchant risk," says Richard Rae, head of loan syndications, at Societe Generale in London. "There was a lack of knowledgeable investors for these types of deals and a successful syndication required all of the banks willing to book merchant deals to be brought in."

By the time Shoreham came to the market there was a feeling that locating sufficient capacity in the market would be difficult to achieve. In some respects this was proved true and the deal had to be offered to two sets of banks. Although partly was this due to constraints on which banks could be invited set by the sponsors. Nevertheless its lack of a fast and oversubscribed close begin to cause bankers to feel that perhaps now there was no spare bank capacity in the UK for merchant assets. "There was definitely concern over the level of appetite left in the market," says Rae at SG.

The news that Societe Generale was due to begin the sell-down of its £240 million project financing for Great Yarmouth Power Limited IP added to the sense that the market was in for a real test and some bankers were predicting that these deals would only get harder to close successfully.

So when bankers looked at the size of the two coal acquisition facilities against the background of difficult to sell gas deal deals there were big doubts whether there would be enough appetite for even one of these transactions let alone both. Even some of the deals' arrangers were taken a by surprise at the extent of the deals success. "The market just seems to have opened up and really found some liquidity," says Rae at SG. "Having the two in the market at the same time doesn't appear to have caused any problems and both have been incredibly successful so far."

There is a definite sense of surprise among project financiers over the extent to which their earlier concerns over capacity have been proven wrong. "The bank market has shown huge capacity for merchant power deals this year," says Tony Marsh, director, head of utilities, project finance, at Deutsche Bank in London. "Many more banks are now prepared to take on merchant risk than was expected at the start of the year."

Indeed, the universe of potential investors for merchant assets has ballooned to around 50 or 60 institutions - many of which had very little experience of merchant deals before the third quarter of this year. Quite why this appetite has emerged so unexpectedly is difficult to explain. Partly, at least, it is a reflection of the growing maturity of the market. "After a number of these deals have been put through the market banks begin to get more familiar and comfortable with the concept of these deals," says the head of power at an international project finance house in London. "People begin to understand the idea of market risk and the ways in which to evaluate it in relation to the specifics of an IPP."

Market risk is very much the key to the power business in the UK and events around the world have played a role in helping investors to put it into some perspective. "There has been a growing realization that power purchase agreements and contracts for differences are not as valuable as was once thought," says Marsh at Deutsche Bank. "These types of contracts have been challenged in the US, Pakistan and Indonesia, for example. The important thing is not whether there is an offtake contract but whether the asset is a low cost producer."

For the coal deals the idea of low cost power generation is perhaps not the most obvious one. The consensus has been that gas-fired generation will always beat coal-fired generation in terms of efficiency. However, with coal as cheap as it is and with forecasts for coal prices to continue to fall over the next 10 to 15 years, bankers are financing assets which will have a declining cost base over time. At the same time these assets present very little construction risk and access to immediate cashflows.

Bond markets - coming back?

But the power market extends beyond the confines of the syndicated credit market. After a couple of bond financed contracted plants in the past few years, the much anticipated use of the capital markets for a UK merchant IPP came in late October when Warburg Dillon Read announced its intention to launch a bond issue to refinance the bank debt it had put in place for Entergy's Damhead Creek plant - this will be the first public bond financed fully merchant plant in Europe.

The bonds have been assigned a preliminary rating from Duff & Phelps Credit Rating of BBB- for the £270.8 million class A secured bonds due 2023 and BB- for the £54.1m class B subordinated bonds due 2018.

The deal was originally set to be financed through the bond markets, however the sponsor chose to take it through the bank market after bond appetite fell away. WDR acted as arranger of the bank financing which was structured into senior facilities amounting to £463.4 million and a subordinated debt tranche worth £36.1 million. Pricing for the main project tranches ranges from 115bp to 145bp with maturity set at 17 years.

The deal will be an interesting test of investor sentiment towards merchant risk. In its preliminary ratings, DCR points out the uncertainty of the evolving UK power market, gas price uncertainty and the merchant risk of the project as some of the key issues to investors. "The project's rating encompasses the risk of future uncertainties within the British power market and further endorses the applications of securitization within the project finance arena," says Jeremy Church, analyst at DCR in London in the preliminary ratings document. The project is also unusual in its lack of external credit enhancement. "The transaction has been structured without a monoline guarantee as the investing community is increasingly prepared to accept unenhanced project finance bonds," comments Church.

Other forms of capital markets instruments have been used to finance elements of power deals in the UK this year. Perhaps the most exciting area of this is in the securitization of equity dividends on plants. Earlier this year, Barclays Capital placed £110 million of bonds in the private market securitized on the dividend stream from Enron's Teesside power complex.

The inherently subordinated nature of these deals can provide a tempting yield pick-up to investors, although so far the investor base for these assets remains limited.

"The capital markets are increasingly being used as a source of finance for UK power projects both for long term senior debt and as a source of subordinated or structurally subordinated debt," says Ian Jefferson, director, at Barclays Capital in London. "UK Investor appetite is continuing to grow for well structured project bonds of investment grade. Appetite for sub- investment grade though rather smaller is there and will grow."

Beyond this, there is also widespread expectation that AES will launch a subordinated bond to refinance part of the bank facilities on its Drax acquisition over the next few months.

But while coal has dominated proceeding in the second half of 1999, few expect this to remain the long-term trend for UK power. "It is unlikely that you will see any significant new build coal-fired plant in the UK in the foreseeable future," says Jefferson at Barclays Capital. "There is not a shortage of capacity at the moment and the gas-fired moratorium is not expected to last indefinitely. The capital cost of new coal plant (including FGD or similar) per MW is significantly greater than that for gas-fired plant. So unless you believe that , on a sustained basis, coal can provide electricity at a per kWhr variable cost sufficiently cheaper than gas to overcome the capital cost disadvantage, new build is likely to be gas -fired (once the moratorium ends). Also, while finding a suitable site for new build gas-fired is not easy, it is easier than for new build coal-fired. The capital costs of these projects are too high compared with gas-fired plant. Coal assets will only come through refurbishments and upgrades."

With the UK government showing no signs of lifting the gas-fired plant moratorium, overall deal flow into 2000 could be seriously disrupted. The moratorium could last for a further 18 month although many bankers predict there will be movement on it some time next year. The net effect is likely to be a slew of gas deals towards the end of 2000 with banks bidding furiously to win some scarce mandates. If so, the market can expect to see further innovation and new levels of aggression in terms of structure and pricing. The question will be whether the market's demonstrated capacity to take on these deals persists.