From Pennsylvania to India, sponsors and lenders of coal-fired power projects are facing lean times. New power developments struggle to attract both permits and funding, during an economic slowdown that takes in ever more countries. Financings for existing projects confront regulatory changes, cost overruns and unfavourable shifts in fuel prices.

These difficulties take in acquisition financings and construction financings for US projects, which have been the victims of the plunge in US gas prices and construction overruns. They take in the Australian power market, where a new carbon trading regime almost derailed the refinancings of several generators. In India, projects running on imported coal are struggling to pass through price increases to offtakers. In Europe, new coal development is almost at a halt, and in the UK the country’s largest coal generator, Drax, is pressing ahead with plans to move to burning 90% biomass.

What is most surprising about all these difficulties is that – with the exception of Australia – moves to price in plants’ carbon emissions have not be the source of their difficulties. Indeed, if the incoming Obama administration had managed to introduce a carbon trading regime, the bloodletting at coal-fired independent power producers might have been even more intense.

Carbon coping

The Australian move towards an emissions trading regime featuring a floor price for carbon is hitting coal generators hard. The Australian government has been working on a trading regime for around six years, mindful that the country is one of the developed world’s worst per capita emitters of carbon dioxide. It had offered some support to help generators move to the new system, and in recent weeks has suggested that it will link up with the EU trading system, which would effectively involve reducing the floor price.

But the changes came too late for InterGen and GDF Suez/IP, which had to step up with considerable sponsor support, and marshal relationship lenders with little project finance presence, to refinance their generating assets in the country. Australia’s support for brown lignite coal -fired generators was more generous than its support for black coal plants, which are more efficient. Lignite generators found the refinancings a little – and only a little – easier.

Of the four financings for Australian coal assets to close in the first half of the year, only one – Loy Yang B – was non-recourse, and that drew heavily on relationship lenders of part-owner Mitsui. Mitsui only owns 30% of the 955MW lignite-fired plant, to GDF’s 70%, but the A$1.062 billion in five-year debt has very little of the European bank content normally expected of a GDF-led project financing. Participants were Aozora (A$30 million), ANZ (A$95 million), BNP (A$95 million), BTMU (A$154 million), CBA (A$158 million), Development Bank of Japan (A$120 million), Mizuho (A$95 million), NAB (A$140 million), SMBC (A$95 million), and Sumitomo Mitsui Trust (A$80 million).

GDF’s other asset – the 1,600MW Hazelwood plant – is also lignite-fired, but was refinanced with a corporate loan. This loan had a higher European presence, and included some lenders that do not make project finance loans. The three-year A$622 million ($621 million) corporate loan was provided by ANZ, Bank of America, Bank of Scotland, BNP, BTMU, CIC, Credit Agricole, Deutsche, Dexia, Nord/LB, RBS, SG, United Overseas Bank, WestLB and Westpac.

InterGen’s black coal-fired Australian operations – the 920MW Callide C and 850MW Millmerran power plants – were also refinanced with short-term corporate facilities. Callide C’s sponsors are InterGen and Huaneng Power, through their joint venture Ozgen, and the state of Queensland, and the new A$346.5 million ($347 million) four-year facility for Callide C comprises a A$126.5 million tranche, a A$150 million tranche and a A$70 million revolving credit. Lenders are KBC, BOS International, NAB, BNP Paribas and Mizuho.

The new debt for Millmerran – which adds Marubeni, Energy Investors Funds and Tohoku Electric to InterGen and Huaneng as sponsors – is A$457 million and is split between a A$247.5 million four-year term loan, a A$120 million four-year term loan, a A$30 million three-year revolving credit and a A$60 million three-year letter of credit. Lenders are ANZ, Bank of Communications, ICBC, China Construction Bank, Investec OCBC, Credit Agricole and Mizuho.

The sponsors of these assets might have been eligible for short-term financial support from the federal government, which would have bridged them to the emissions trading market settling down, but apparently rejected the terms attached to the support, structured as a loan, as too restrictive and unlikely to work alongside existing lenders. Instead they put their balance sheets – and banking relationships – to work.

Carbon trading and project books

One of the most compelling testaments to Goldman Sachs’ ability to time the market is its sale of its portfolio of Cogentrix plants to EIF in September 2007. Cogentrix was founded in 1983 as a developer of mostly coal-fired cogeneration plants, and was acquired by Goldman in 2003, in the messy aftermath of Enron. Four years later it sold 80% of the 14-strong Cogentrix portfolio of operational plants to EIF, but kept the remaining 20% and the Cogentrix brand name, and promptly moved into solar development.

EIF, through its US Power Fund III, financed the acquisition through an $850 million holding company financing led by Credit Agricole (then known as Calyon). The syndication of the deal, which took place towards the end of 2007, had several detractors, and was subordinate to several project level financings. But it sold down, thanks to high equity contributions and the portfolio’s contracted revenue streams. EIF bought the remaining 20% from Goldman in April 2011.

But eight of the 14 plants were coal-fired, and some of the power purchase agreements for them did not allow for the impact of rising coal prices to be passed through to offtakers. One of the projects, 112MW Northampton Generating, filed for chapter 11 bankruptcy protection in December 2011. The Pennsylvania-based plant, subject to a little over $71 million in tax-exempt bond debt, is trying to extricate itself from uneconomic power purchase agreements with Metropolitan Edison and PPL.

Most of the rest of the coal plant PPAs did not allow the generators to pass on the costs of increased environmental compliance to offtakers. “I took over my portfolio at about the same time as Obama came in,” noted one banker with exposure to Calypso, “and I was nervous for quite a while about what a carbon trading regime would do to the portfolio.” The obduracy of Republicans and Democrats from coal-mining states, who were able to defeat moves towards green-house gas limits, probably saved Calypso lenders’ skins.

In recent weeks, the US Court of Appeals for the District of Columbia rejected a move by the US Environmental Protection Agency to insist on the installation of scrubbing equipment for sulphur dioxide and nitrogen dioxide on the basis that these plants affected other states downwind from them. The ruling will provide some relief to merchant generators such as Edison Mission’s Homer City, which is in the midst of restructuring negotiations, though tougher rules are likely to come into effect from 2015, the Mercury and Air Toxics Standards, which would make the argument over cross-state emissions moot.

The Cogentrix plants were developed before policymakers paid much attention to green-house gas emissions. The small number of new coal-financings that closed in the last decade tended to include language that passed on the burden of environmental compliance to offtakers. They also tended to use supercritical coal technology and scrubbing units that made them more efficient and less likely to experience compliance shocks.

Newbuild teething troubles

Coal plants, however, tend to suffer from more problems during construction than gas-fired plants. The Cogentrix portfolio, based on standardised designs, was comparatively trouble-free, but coordinating the operations of boilers, turbines and coal-handling equipment means that bringing coal plants into operations can be a fraught process.

LS Power closed project financings for two new coal plants in the last decade – the $1.64 billion Sandy Creek in August 2007 and the $970 million Plum Point deal in March 2006. It was careful to pass on all environmental compliance costs to offtakers, but Sandy Creek, after an explosion during testing of its boiler tubes, is set to come online a year late. Builders risk insurance on the plants’ construction contractor, a joint venture of Kiewit, Black & Veatch and Zachry, is likely to meet the costs of repairing the damage.

LS Power, which at close owned a little under two-thirds of the project, endured an exhaustive permitting process, for one of the first coal plants to go forward in Texas since 1988. At least one legal challenge was still under way when the $1 billion Credit Suisse and RBS-led debt financing for the plant closed in August 2008. The financing was meant to be a B loan, but was, with minimal tweaks, eventually sold into the bank market.

The plant has some of the most modern technology available, and would have passed the most stringent of the regulations that the DC court rejected. By excusing older and dirtier plants from making costly upgrades, the court has blunted the competitive advantage that Sandy Creek might have had over the dirtier competitors.

Its merchant capacity benefits from a gas price hedge with Credit Suisse that protects it from movements in the price of gas below $7.50 per million BTU (the price dipped below $2 earlier this year and is now at a little over $2.60). The rest of the plant’s capacity, as with LS’ other coal financing, Plum Point, was sold to a public power entity either outright or under a long-term contract – with full pass-through of environmental compliance costs.

Coal plants have typically enjoyed such a substantial fuel cost advantage over gas plants that their strong operating margins tend to counteract the availability and performance problems that plague them during the early years of operations. But this assumes patient and understanding offtakers or hedge providers, and sponsors that have included enough slack in a project’s financial structure to absorb these shocks.

The First Reserve-owned Longview supercritical coal-fired project has already undergone one restructuring since it closed in February 2007, a mid-2011 refinancing that itself followed a failed amendment to the $1.1 billion debt package. When Longview’s financing closed, the 695MW plant was a rare example of a supercritical power plant to close a project financing. But implementing this boiler technology was a troubled process, and led to the plant coming online 5 months late.

In the mean time, First Reserve increased the total financing amount to $1.75 billion, terminated a gas hedge with Goldman Sachs, which was heavily in the project’s favour, for an upfront payment, and assigned to lenders excess revenues from a next-door coal mine – Mepco. Access to this captive fuel source is a big source of lender comfort, because gas prices, and thus power prices, in the project’s PJM power pool have not moved in the project’s favour.

“I think that’s one of the biggest differences that the newer plants have with the earlier coal plant financings,” says one US power lender. “They usually have better efficiency, but it looks like we’re in a permanent low gas-price environment now. Coal generators don’t have the breathing space they used to have when fixing teething problems.”

India suffers from Indonesia

But the patchy performance of a handful of US plants pales next to what might be in store in the Indian power sector. Giant coal-fired power plants – the ultra mega power projects – have provided the standout project financings in India, and many of them run on imported coal. Standard Indian power project finance practice is to close a deal first and worry about the offtake arrangements later. Until a developer can line up an offtaker, and after that access long-term offshore dollar financing, it often provides a suite of guarantees to lenders.

Tata Power’s Mundra power project is one of the highest-profile casualties of increases in the price of coal exported from Indonesia. Mundra, a 4,000MW facility, is subject to $3.2 billion in debt, from a mixture of Indian and offshore lenders. It has its power purchase agreements in place, with Gujarat (1,900MW), Maharashtra (800MW), Punjab (500MW) and Rajasthan (400MW), and is nearing completion.

But the agreements only allow the generator to pass-through cost increases on 45% of its fuel supply, and prices per tonne for Indonesian coal have increased from roughly $36 in 2008, when the financing signed, to nearer $95. The offtakers have so far refused to allow for an increase in tariffs, and Tata has had to ask lenders for a waiver of a debt/equity ratio covenant and minimum DSCR covenant to continue drawing on the debt.

Tata, like Longview, benefits from a captive source of supply, though this consists of 30% stakes in two mines in Indonesia, and it may, like Longview, have to assign 75% of its dividends from these stakes to lenders to keep them happy. In the mean time, it hopes that India’s Central Electricity Regulatory Commission will countenance an increase in the tariff on the plant’s 25-year PPAs from Rs2.26 ($0.04) per kWh to something nearer Rs3.

Reliance Power’s Krishnapatnam plant has a slightly higher per kWh price on its PPAs with 11 state electricity boards – Rs2.33 – but it has still launched arbitration proceedings against them. Construction on the 4,000MW coal plant is halted, and Reliance has tried to prevent the offtakers from drawing on letters of credit it posted in support of its PPA obligations. Given the widespread blackouts that hit the country in late July the government is likely to step in, and has already cut duties on imported coal, and any signs of distress in the banking sector will probably force its hand.

The bright spots

Coal development is still going strong in Indonesia, the source of the Indian generators’ woes. Lingering lender concerns about Indonesian power centre on the willingness of state power company PLN to honour its offtake commitments.

J-Power (34%) Adaro (34%), and Itochu (32%) are sponsors of the 2,000MW ultra-supercritical Central Java IPP, which will benefit from a guarantee from the Indonesia Infrastructure Guarantee Fund, which was set up to enhance the credit of PPP projects. The sponsors hope to start construction on the plant in October, despite some lender concerns about the mechanics of the guarantee, which is designed to replace the bilateral letters of support that Indonesia has offered IPP developers in the aftermath of the late-1990s Asia crisis.

Chile is also meant to be a bright spot for coal developers, because its growing economy struggles to source gas imports either from its unreliable neighbor Argentina or through its limited LNG import facilities. It has found that coal plants attract less scrutiny than large hydro projects, and a deregulated, but dollar lender-friendly, power market favours cheaper coal facilities.

However, in late August a court in Santiago rejected the permit for the $5 billion, 2,100MW Castilla power plant, whose sponsors are E.ON and MPX. The court cited environmental concerns but indicated that the developers might be able to submit a new environmental impact assessment for the plant and related port infrastructure at a later date. MPX’ main shareholder, Brazil’s Eike Batista, has already blasted the Chilean authorities, and Chile’s mining industry still needs low-cost power. But local politicians and environmental groups, which have been extremely successful in derailing power projects, have claimed another major scalp.

New answers?

Technological change, adaptation of existing plants to new fuels and the development of new markets for what have traditionally been waste products are the key drivers to bringing coal-fired power back as a competitive alternative to gas-fired units.

For example, in the UK, Drax Power is moving forward with plans to replace 90% of the fuel in half of its 3,960MW of capacity to run on biomass instead of coal. The July renewables obligation certificate review, which affirmed the subsidies that biomass generators would receive, makes retrofitting or repowering coal stations to run on biomass attractive. Drax is in the process of closing a £100 million ($159 million) loan with the M&G UK Companies Financing Fund to support the upgrade work.

The main hope for coal in the US is now integrated gasification combined-cycle technology, which, when allied to carbon capture technology, might allow a plant to win a permit and close a financing, though the costs attached to IGCC have so far proved daunting. The history of FutureGen, which enjoys heavy US government support, highlights some of the issues. The US Department of Energy has had to keep the project afloat throughout a series of changes in ownership and scope.

The plant was originally a 275MW new facility with four utility sponsors – AEP, PPL, Luminant (formerly TXU) and Southern. The utilities subsequently dropped out and now a coal miner-dominated group of sponsors – Anglo American, BHP Billiton, Caterpillar, China Huaneng, CONSOL Energy, E.ON, Foundation Coal, Peabody Energy, Rio Tinto and Xstrata – are working on a project to retrofit an old Ameren plant with the technology.

Summit Power is also benefiting from US government support – $450 million in grant funding from the DoE – and is now looking for $1 billion in equity from a group of investors that includes Sinopec. The 400MW plant will also require $1.8 billion in debt, for which Euler Hermes, an old supporter of coal technology in the US dating back to the 1990s, may also provide support. CPS Energy will buy half the plant’s output under a 25-year offtake agreement.

Summit’s revenues will benefit from it producing limited amounts of urea fertiliser as well as power. It also plans to sell its carbon dioxide output to oil producers that use enhanced recovery methods, a solution that, if it works, would mitigate both economic and environmental concerns at a stroke. The revolution in US oil and gas production, to date the nemesis of coal-fired generators, could yet be their salvation.