Speculation about the future of the UK's electricity market has been very one-sided. The new trading arrangement has introduced insuperable obstacles to investment, especially for developers ? at least according to its detractors. In fact, it has not. Despite the difficulties dogging the industry, the market is now gearing up for some high-profile deals, including the first greenfield power projects since NETA's start last March ? albeit with a new development approach that tackles the revised system and its peculiarities.

With plants being increasingly treated as trading positions as much as assets on the ground, independent power producers are trying to come to terms with a new risk model that does not typically provide a long term power purchase agreement to guarantee revenue streams. At the same time, lenders are weighing up approaches to financing power projects, while assessing new credit risks, particularly if long term lending against merchant operations is to remain viable.

True, the sector is depressed. Forced divestments and burgeoning competition (with an influx of new entrants vying for market share) over the last three years have sent market prices plunging. Coupled with high fuel prices, this has tended to feed a worryingly low ?spark spread? (or the margin between power prices and marginal operating costs).

Though it has achieved its goal of reducing consumer power prices, while making the electricity market, insofar as its possible, more like any other commodity market, the new trading arrangement has thrown up a unique, though not overwhelming, set of issues. And the main risk for generators is exposure to unpredictable balancing mechanism prices, in case of shortfalls in output relative to what their contracts demand.

More relevant, however, is the endemic supply question. The UK market currently has a capacity margin of roughly 25%, the vast majority of which is thermal or nuclear. Demand is forecast to grow by around 1% per year. Indeed, given the apparent oversupply scenario, the value of power stations has been tumbling. This trend has also engendered opportunism on the part of foreign sponsors happily taking advantage of low asset prices. International players have been making key acquisitions at near fire sale prices, as generators burned by low wholesale prices divest assets that were once bought at heavy premiums.

The government has also approved a slew of new gas-fired projects, totaling 8GW, over the last year since it eased a strict consent policy designed to protect the coal industry from increased gas usage. It is unlikely, according to analysts, that the majority of them will move forward in the short term. On the face of it, then, it would appear that there is little demand for new baseload capacity.

But this understanding hinges in part on the extent of any plant withdrawals. Greenfield development in this climate would seem to be a bet on such impending capacity retirement, particularly of certain aging nuclear assets. It is also a bet on specific locational or other advantages of particular benefit to individual schemes.

In fact, banks are still willing to finance certain greenfield deals, admitting, though, that they will be done on a more conservative basis. ?There's still a good appetite for well structured deals ? there's a lot happening in the industry, but its not all going to happen overnight,? says one banker familiar with the sector.

Price forecasting for both fuel and electricity has become more cautious. And increased competition has meant that developers ? and lenders ? have had to look much more carefully at spark spread analyses.

?As long as the project's fundamentals make sense in the new environment, there's still scope for new build. But what this underscores is the urgency of getting the economics right,? says Mark Aplin, head of Citibank's European power team. With two notable greenfield financings currently edging into the market, the view is clearly that the economics, at least for these deals, does stack up favorably.

Says Royal Bank of Scotland's (RBS) Alan White, ?there are a lot of nuclear facilities set to retire, and something needs to replace them. Unless something magical happens, we'll need new gas build. We're actually closer to a supply/demand equilibrium than we've ever been.?

Green pastures

The success of any power trading arrangement, some argue, could be predicated to a large extent on the ability of new market entrants to project finance single asset IPPs without having the broader resources of large utilities. This is precisely what is happening in the UK.

The first new-build facility to have reached financial close since NETA's advent is Conoco's 730MW combined heat and power (CHP) plant at Immingham, on the Humber river. Arranged by RBS, the £260 million deal was signed at the end of January.

The loan is understood to have a 20-year tenor and the debt/equity split is 65/35, with equity being injected upfront. RBS is currently deciding on a strategy for syndication, to be launched at the end of February.

The first greenfield financing of the new market, the deal could plausibly set the benchmark for financing new plants going forward.

Gas will be supplied by Shell and there is reportedly a link between the gas price and the power price, which, in principle, will allow the IPP to manage its price risks more effectively.

The plant will supply steam and electricity to the Humber refinery, steam to a neighbouring refinery and electricity to the National Grid. Completion is expected in early 2004.

Intergen's Spalding deal, the second greenfield IPP in line to hit the markets, is being arranged by Citigroup and Barclays Capital. A £400 million loan will finance the new 900MW plant, to be fitted with the latest CCGT technology.

The financing package is understood to include an equity bridge. The debt requirement will be roughly 80-85%, and the loan will strike a tenor of 20 years. Financial close is expected by the end of the first quarter.

Intergen will be the sole owner of the facility, although Centrica has an option to acquire 50% of the plant.

Feeling the combined heat

One of the demands imposed by the new market on power projects is that plants use well proven, or at least reliable and flexible, technologies, instead of designs which simply seek to maximize thermal efficiency. Contracting between generators and offtakers commits the generator to deliver defined amounts of electricity at specific times ? failure to do so creates instant liability, and possible losses, for the generator. As such, plants which have the flexibility (of being able to shift between base load operation and increased operation to meet peak demand) therefore have a clear advantage.

The Immingham plant benefits strongly from its use of CHP technology ? one of the ?cleanest and most efficient ways to generate power,? according to Conoco. In general, though, CHP plants do not have the optimal ability to control the release of power onto the system. The government, however, has exempted certain ?good quality' CHP plants from the Climate Change Levy, thus fixing the technology squarely within its overall energy policy. This, says Conoco, is one of the primary drivers behind the plant's development.

With a CHP plant, says RBS's White, very competitive prices are possible, although there are few sites that can sustain a large CHP plant, given their substantial water requirements. Nonetheless, the plant's design, he says, contributes significantly to its bankability.

The older combined cycle gas turbine (CCGT) plants, however, were designed to maximize thermal efficiency, and cannot be regulated easily. In fact, plants may have to be run less efficiently to achieve the flexibility required to compete for the high prices in the balancing market. In this respect, some of the older coal and fuel-oil fired plants are substantially more flexible.

Says one developer, ?gas prices are relatively high but coal and other fuel costs have also gone up. Last year coal plants had a respite from gas but these plants are very old, and their owners are under extreme financial pressure, particularly with many of them having been purchased at high prices.? Many of the older coal assets are set to fit flue gas desulphurisation (FGD) to their units, thus keeping in line with emissions controls, while allow for increased operational life.

The newest CCGT plants like Spalding, on the other hand, are apparently being designed with operational flexibility in mind.

According to a recent report from Moody's Investors Service, a trade off may occur between ?the need for high efficiency, and thereby long-term cost effectiveness, and the need for low risk proven technologies.? This may even translate as requirements for EPC contractors to provide additional guarantees to support their equipment sales.

Resolving credit risk

The oversupply argument against newbuild loses momentum in light of the Spalding and Immingham deals. Both are also hedged against technology risks posed by the new market system.

Given the dispatch risk (the risk of generating unsellable power) and counterparty credit risks that the new arrangement throws up, devising the right strategy is key for both developers and lenders. And the mechanisms to deal with such risks are already falling into place, both in theory and in practice.

One solution lies in the strength of power trading operations, as much as in the kinds of power contracts ultimately negotiated. In light of counterparty risk, developers need to have a much more flexible trading strategy. For new entrants, this means putting in a trading contract with competent and well-established traders.

To this extent, says White, ?the developers have to be cautious about who they're trading with. They have to look carefully at the length of the contract and the creditworthiness of the trading partner.? For newcomers, insists White, the risks are obvious: ?as soon as the market sees a new single shot IPP trying to trade, they're going to react with suspicion.?

According to Aplin, the effect of such cumulative risks will simply be that ?debt and equity will become more intelligent about assets.? This is to say that financiers will necessarily differentiate in terms of plant flexibility and contractual structures.

The alternative, of course, is to enter into tolling agreements, as in the case of Intergen's Spalding plant. There, Intergen has entered into a tolling agreement with Centrica on two-thirds of the output. The balance will be subject to spark spread risk.

?With Spalding's tolling agreement,? says one developer, ?they have the necessary driver to get this deal done. A greenfield CCGT plant without a tolling mechanism would be much more dubious.?

Other means of mitigating operational and trading risks, aside from tolling, are also readily available. For example, suggests Moody's, trading arrangements may require the provision of collateral. Commercial arrangements, such as security, could be customized and, accordingly, requested based on certain trigger events. These might include instances when credit exposure exceeds a certain level of unpaid receivables, or might even be based on credit rating triggers.

Another approach calls for debt service reserve accounts to be available to collateralize security calls, which might arise in such trading operations, throughout the life of the project. In other words, structure additional reserve liquidity into the project to account for trading irregularities.

Notwithstanding such concerns, perhaps the most important fact is, as Moody's puts it, that ?whilst the NETA framework raises new risks that need to be managed, these should be considered within the context of risks that already feature in many project-financed IPPs and that may be of greater consequence.? The implication is that more fundamental market risks, such as price and volume risk, need to be addressed appropriately to ensure that debt holders benefit from upward price swings and are protected against downturns. However, says the agency, ?the best protection for projects ultimately comes from being low cost producers.?

Dawn of the mini-perm

Both Spalding and Immingham deals, according to those familiar with their (as yet undisclosed) mechanics, are comfortably structured for long term lending, albeit in the absence of traditional long term power purchase agreements.

But a recent development in the UK power finance market has opened some interesting possibilities. With uncertainty in some quarters about extending long tenor loans without long term contracts to support payment obligations, the classic project finance template (of a single plant financed with 20 year non-recourse debt, backed by a long term power purchase agreement) may yet give way to a preponderance of hybrid and short term financing solutions.

Witness the recent Rugeley deal. International Power acquired the 1000MW coal-fired plant from TXU in June last year. Mandated banks ING and TD Securities, together with BoTM and Credit Lyonnais, arranged off-balance sheet funding for the purchase, raising £190 million in seven year debt.

The deal is noteworthy for its ?mini-perm? structure, a first in the European power market. The rationale is this: a short-term loan with lower amortization requirements will provide sponsors with time to strengthen their projects before offering them up for permanent financing. In this case, a short-term structure would also seem to insulate against whatever perceived uncertainties surround the current power market and its (gradually subsiding) price volatility. It then opens the door for refinancing at the end of the loan's term. If refinancing has not occurred by the end of the 7-year tenor, a 100% cash sweep comes into play.

International Power has a four-year tolling agreement with a TXU affiliate to supply coal and buy the plant's output. When this expires, the project will operate either on a purely merchant basis or will secure new tolling or power purchase contracts.

The mini-perm structure has been a common fixture of the US power market in recent years, where the tool is typically used to bring a power plant from construction to initial operation. At that point, loans are then meant to be taken out with less expensive permanent financing ? bond offering, long term loan, synthetic lease or another appropriate instrument.

But other bankers remain sceptical: ?Banks are still wary of refinancing. All it does is put money into the sponsor's pockets very early on, but it doesn't really fit with the appropriate project finance risk. It may be better to enter into a long term loan and take a view when it's the right time to refinance, rather than forcing it that way in, say, 5 years.?

But Rugeley's financiers seem confident that circumstances for long term financing will be more favorable in a few years, at which point appetite might even exist for refinancing through the European capital markets.

Previously, a view to refinancing was the impetus behind NRG's £390 million Killingholme acquisition. That deal, which closed at the beginning of 2000, included a cash sweep after year six on one of its debt tranches. As the European capital markets develop, shorter term financing approaches for power deals may indeed become the preferred flavour.

Going to the fire sales

With the rapid demise of power plant value over the last year after a steep decline in the price of wholesale electricity, many foreign sponsors have discovered a lucrative way of entering the UK power market, in some cases picking up assets from other developers at remarkably low prices.

The market has seen several deals taking shape to support asset transfer activity, such as the Rugeley deal, part of TXU's generation asset divestment program which seeks to reduce its debt burden by $1 billion.

Another notable transaction coming to the market is American Electric Power's (AEP) purchase of Edison Mission Energy's 4000MW coal fired assets, Fiddler's Ferry and Ferrybridge, to be taken out by a project financing by the end of the first quarter. A £650 million corporate bridge loan was recently completed for that purchase by Barclays Capital, CIBC World Markets, Commerzbank and WestLB.

AEP is hoping to advance its European wholesale strategy with the purchase and is confident about the plants' competitiveness against other coal assets. The plants are particularly flexible, and are capable of burning a wide variety of coal. But Edison Mission had a very different story to tell, particularly after being forced to sell the plants for half the price it paid for them just over two years ago, after having suffered considerable operating losses. Aside from being hit by the drop in electricity prices, the company had also been stung by the California power crisis, which saw one of its subsidiaries, Southern California Edison, on the verge of bankruptcy.

The long term non-recourse financing will be arranged by the same team as on its bridge loan. Debt is likely to be for roughly 50-60% of the purchase price. The plant's output is understood to be hedged for the first few years of operation.