Coal-fired power project developers in the US had been basking in the best conditions for financing new projects for decades. A combination of high gas prices and increased government support have allowed three large-scale independent power projects to go to market this year, and utilities, both investor-owned and non-profit, have been investing heavily in new capacity on their own account.

The three independent projects attracted strong bank interest and competitive pricing, in a year when large greenfield power projects were slow to come to market. In February, GenPower and First Reserve closed $1.1 billion in debt with Goldman Sachs and WestLB to fund construction of a 769MW supercritical coal-fired project in West Virginia. In April, LS Power refinanced its share of the 664MW Plum Point plant with an $819 million Ambac-wrapped loan provided by Royal Bank of Scotland.

On 30 August a club of banks led by Credit Suisse and RBS completed a $1 billion loan for the 900MW Sandy Creek supercritical coal-fired project. That deal, originally conceived as a B loan financing, was restructured as a bank deal when the credit crunch first hit. The banks, which had been among the lenders on some of the Longview tranches, stepped up with alacrity.

But recent developments – including the shifting sentiment in US debt markets and a growing public awareness of carbon dioxide emissions from the power industry – have clouded coal's promise. Until recently large parts of the Western US, as well as parts of the South and Mid-Atlantic, were assumed to be open to coal development. Now, bankers are struggling to come up with more than a handful of viable financing candidates.

The cause of this consternation is the fate of the permit for the Holcomb power project in Kansas. The state is seen, rightly or wrongly, as a useful proxy for opinion in conservative America and New York-based bankers assume that, behind Texas, it should be the friendliest state towards a power developer in the US.

The Holcomb decision

But on 18 October Roderick Bremby, secretary of the state's department of health and environment (KDHE), rejected a permit for the expansion of Sunflower Electric Power Corporation's Holcomb plant. Sunflower, a wholesale producer owned by six regional cooperatives, owns 586MW of thermal generation, including the 360MW coal-fired Holcomb I unit.

Sunflower, the Golden Spread Electric Cooperative, and MidWest Energy want to build a 700MW unit at the site, with Golden Spread owning the majority of the capacity. Tri-State Generation would have built a second unit of 700MW next door. Both will use supercritical pulverised coal technology, and also incorporated eye-catching elements such as an algae-to-biofuels project that would run on some of the carbon dioxide from the plant.

The three co-ops filed a permit application with the KDHE in February 2006, and wanted to raise the necessary recourse tax-exempt debt and start construction on the first unit this year, with Tri-State to follow a year later. The KDHE, which has the support of the state's governor, declined and cited the two units' estimated annual emissions of 11 million tonnes of carbon dioxide per year as a main factor in its decision.

Sunflower recently appealed the decision, saying that neither the federal Environmental Protection Agency, nor the state's own regulations, consider carbon dioxide a pollutant. The developer also noted that the project would have attracted additional transmission capacity to the state to benefit wind producers. But the biggest factor in the opposition was that so much of the plant's output would be exported from the state to its neighbours.

The sentiment, that communities would rather not shoulder the burden of emissions in their vicinity from plants that serve a load elsewhere, is not a new one. The Kansas decision was not even the first sign of a turn against coal in the region. TXU's plans for 11 coal plants in Texas encountered similar protests from the state's politicians, particularly the mayors Houston and Dallas.

Lone Star dissenters

TXU had proposed building 11 new plants, all of which would have run on coal, with the aim of undercutting the majority of the state's other producers, which burn comparatively expensive natural gas. It went so far as to solicit both debt and equity commitments in late 2006 for the slate of construction projects, although several analysts contacted by Project Finance still consider that it never intended to build as much as 8,600MW of capacity.

By December that 8,600MW was scaled back to 6,000MW, although Merrill Lynch, Morgan Stanley and Citigroup were still pre-marketing as much as $9 billion in debt for the plants. It was only when TXU succumbed to a leveraged buy-out approach from Kohlberg Kravis Roberts and Texas Pacific Group that it slashed the number of plants from 11 to three, in order to gain the support of state regulators and non-governmental organisations for the buy-out.

The Texas mayors, and most other opponents of new coal plants, point to integrated gasification combined cycle (IGCC) as the preferable solution to looming shortages in generating capacity. IGCC is designed to operate more efficiently than supercritical pulverised coal projects – the current state of the art for coal – and offer an easier way to capture carbon dioxide emissions.

But IGCC has a slim track record, including five small-scale plants in the US, and Nuon's 250MW Buggenum plant in the Netherlands. The technology is feasible, according to its proponents, although several factors, including altitude, can have drastic effects on the proportion of the time that plants can operate.

The plants' costs are likely to be much higher than the current generation of coal-fired plants, which already cost more to install, if less to run, than gas plants. AEP, one of the earliest proponents of the technology, has proposed a 600MW IGCC plant in the east of its service area, and has engaged GE and Bechtel to perform front-end engineering and design work on the project. But it has been careful to obtain approval from the Public Utilities Commission of Ohio to recover its development costs. Its current position is that "AEP will build one or more IGCC units, providing that costs can be recovered through the regulatory process."

The statement should not be read as scepticism about the technology – regulated utilities, after all, are in the business of passing on their cost of service to consumers – but it does show an awareness that the ultimate costs of the technology are far from certain. Nevertheless, two developers, including Global Energy, which has a 540MW IGCC project in Ohio in front of prospective lenders, and Hunton Energy, which has lined up Goldman Sachs to contribute equity to a 1,100MW petcoke-fired plant in Texas, are hoping to interest lenders in the concept.

Federal aid

The best bet for independent developers of IGCC plants, which do not have retail customers to subsidise a venture, is to turn to the federal government to support. In November 2006, nine coal projects, mostly utility-sponsored, received a total of $1 billion in tax credits from the US Department of Energy to support newer coal technologies. Duke Energy and Tampa Electric are both building bituminous coal IGCC projects with a 790MW capacity, and both received $133.5 million in tax credits. E.On and a second project from Duke, both classified as advanced coal facilities, received $125 million credits.

On top of these tax credits, the Department of Energy is also extending loan guarantees to IGCC projects, as part of a wider programme for supporting new power technologies. Originally set at 80% of the debt amount for 16 projects, among them three IGCC projects, the DoE extended the guarantees to 100% of debt amounts, providing the financings feature 20% equity contributions.

The government's understandable desire to make sure that commercial lenders shared in the due diligence on the technology wilted in the face of banks' protestations that they had little ability to measure the risks of the new technology. Two tax credit recipients – TX Energy and Mississippi Power – are also receiving loan guarantees. The third guarantee recipient is Excelsior Energy's Mesaba project, a 603MW unit. NRG Energy, the largest non-utility developer of an IGCC plant, has indicated that it is likely to require some help from government to bring its plans for plants in Texas and New York State to fruition.

If the developer opinion tracks bank sentiment, and no banker canvassed by Project Finance suggested that an IGCC plant would be online before 2012, then any looming generation shortage will not be met through coal. The timescale for nuclear power, assuming, again, that federal guarantees of loans from commercial lenders are forthcoming, is roughly the same.

Nuclear has, if anything a slightly better reputation with lenders. Its operating costs are low, and several utilities, chief among them Exelon, Entergy and FPL, have built up good track record operating plants. Bond investors have accepted some nuclear risk, if incorporated into a larger fossil-inclusive generation portfolio.

Entergy plans a pure spin-off of its merchant nuclear portfolio next year, and bond investors' reception of the debt of the vehicle, currently dubbed SpinCo, will be an interesting measure of nuclear risk's acceptance. Still, ratings agencies will be one pressure upon the finances of utilities with aggressive nuclear development plans. Moody's, for instance, recently warned generators to bulk up their balance sheets before embarking on any nuclear construction programmes.

Cheaper and more cheerful

But beyond the timing of these two new technologies lies the difficulty of containing construction costs. Nuclear and IGCC, as relatively untested technologies, offer severe challenges to developers and bankers trying to settle on a budget. Project bankers have suggested that they might be comfortable with a series of smaller contracts with a cap, as well as some liquidity support or contingent equity.

Concurrently, engineering, procurement and construction contract price inflation is starting to hit the cost of more conventional coal plants. According to a sampling of new coal projects from Standard & Poor's, the most expensive coal plant built on a per kW basis over the last five years was 50% higher than the per kW cost of the cheapest.

The data does not entirely compare like with like, although a good cross-section of contractual arrangements is represented. Most significantly, the three most recent coal project installations are all from independent developers, while the five before them were from public and private utilities.

The presence of publicly-owned utilities can help a coal project go forward, and for both of LS Power's projects, public power entities were significant owners of capacity. Coal producer Peabody Energy has taken this approach to its logical conclusion, putting together a coal-fired project in which it only owns a small slice of the equity.

The Prairie State coal project reached financial close on 1 October 2007. It is financed entirely through the municipal bond programmes of the participating public power agencies. The 1,582MW supercritical pulverised coal-fired plant is located in Washington County, Illinois, close to St Louis, where Peabody is based. The EPC contractor is Bechtel, while Babcock & Wilcox is supplying boilers, Toshiba the turbines and Siemens the emission control equipment.

The project was financed through roughly $2.3 billion in municipal debt, split between the participating bodies according to their share of the project's capacity. The participating agencies and their issuance were Northern Illinois Municipal Power Agency ($391.4 million A2); Kentucky Municipal Power Agency, ($350.56 million A3/A) Missouri Joint Municipal Electric Commission ($567.6 million A3); Illinois Municipal Energy Agency ($675 million, A1) the Indiana Municipal Power Agency ($435 million, A1/A+), and AMP Ohio.

The advantage to the project of using municipal issuers can be substantial. According to the Illinois Municipal Energy Agency, which owns 15.17% of the project, it achieved an average interest rate on its $605 million in tax-exempt and taxable bonds of 5% when it priced the deal in August. This project survived a challenge to its air permit that went as far as the 7th Circuit US Court of Appeals, which upheld the Illinois Environmental Protection Agency's approval of the project.

While the Holcomb decision shows that public power entities cannot be assured of winning permits, they enjoy two huge advantages over independent power producers. The first is a cost of capital advantage, since debt costs are between 100bp and 300bp lower than a private borrower, particularly one without a utility's large balance sheet. The second is that since customer-owned utilities are self-regulated they can pass on the higher costs of a project, whether construction, fuel or carbon compliance, to their customers more quickly.

Carbon dated?

But coal's critics are operating on a national as well as state level. Several environmental groups have initiated campaigns against banks that fund coal producers and coal consumers. The Rainforest Action Network (RAN), which launched campaigns against banks' project lending activities in emerging markets, has singled out Citigroup and Bank of America for protests.

The protests gained a large amount of attention, in part because they provided a focus for the disparate state-level opposition to coal projects. Bank of America, without a great presence in the power finance market, has attracted RAN's ire from its work providing corporate finance to coal miners, while Citi has previously tangled with RAN over its work on the Camisea project.

RAN's 5 November protest, a "die in" at a Washington DC Citi branch, paled next to its earlier campaigns against Citi, which enlisted actress Susan Sarandon to film commercials. Moreover, both Bank of America and Citi are preoccupied with the fall-out of the subprime crisis. Meanwhile, the same day in Orlando, power bankers and utility executives gathered for the Edison Electrical Institute's financial conference unmolested.

A future carbon trading regime is likely to have more impact on the way these banks finance generation capacity. The US has been a hold-out against a mandatory emissions trading regime, and its voluntary market in carbon credits is still in its infancy. But two bills in congress, one from Senators Dianne Feinstein and Tom Carper and one from Senators Barbara Boxer and Bernie Sanders, would set reductions in carbon dioxide emissions.

The Boxer-Sanders legislation mandates slightly more aggressive targets, although the mechanism by which credits are allocated, whether they are awarded or auctioned, will be key to the effect of caps upon utilities' and generators' businesses. Its effects are unpredictable, since carbon compliance costs would hit coal hard, but the effects upon over-all power prices might allow coal generators to collect even better margins than they do now.

S&P's affiliate Platts has produced some estimates of the effect of compliance on the Ebitda that select utilities produce in 2026. Under this scenario utilities and merchant generators with large coal portfolios will do badly, those with large nuclear portfolios will do very well, and those with mixed portfolios will muddle through. Pure gas generators are likely to do well, though, with Platts singling out Dynegy as likely to fare particularly, although it adds a lengthy list of caveats to the simulation.

Gas greater

This result would be a market eerily similar to that of the mid-1990s. During that period utilities and public opinion was heavily against coal, gas was relatively cheap, and contracts to generate power from gas were relatively abundant. Retrenchment in deregulated markets and lender nervousness have combined to keep merchant projects to a minimum.

The big difference, aside from the presence of financial intermediaries in energy markets and the persistence of B loan investors, is the momentum that wind has gained. According to wind's lobbying organisation, AWEA, 2007 will see the installation of 4,000MW of new capacity. But wind is unable to make a large contribution to wider reserve margins.

Power market consultants are now much more circumspect in their predictions of what will happen in US power markets. The source of some of the optimism of the late 1990s and early part of this decade was the widespread belief that regulators would force utilities to shut down their older and dirtier units, and create opportunities for new entrants.

This did not happen, and it is easy to see how regulators, especially during a downturn in the US economy, might turn to coal – the cheapest source of power – regardless of its environmental cost. In Europe, for instance, several utilities are adapting diesel-fired plants to run on a mixture of coal and biomass in response to high oil prices.

Supplies of natural gas to the US are still tight, as importers have to compete with Asian and European consumers for supplies. But prices, at least relative to oil, are still low, since competing cheap coal acts as something of a dampener, and gas is not as tradable globally as oil.

The final reality for project bankers to face is that utilities are much more prepared to build capacity themselves, whether coal, gas, or, increasingly, wind. For independent power producers and their lenders, this skewed competitive landscape is a much greater danger than carbon trading, at least for now.