The credit crunch could be the least of US power finance bankers' worries. An economic downturn and the collateral damage from the collapse of Lehman Brothers could redraw the contours of US power market.

The 2001 economic downturn in the US was a distant memory by the time credit markets hit their 2006 peak. For equity investors, the bankruptcy of Enron, formed, with scandals such as Tyco and Worldcom, part of a broader picture of corporate malfeasance.

For power markets, Enron's collapse was more traumatic, and its effects on the market's structure were much more profound. But the credit crunch has exposed the weakness of this market structure. Meanwhile, newer technologies, which have only really known this post-Enron landscape, may be the biggest sufferers.

The 2001-3 period was marked by distressed asset sales, the withdrawal of commercial banks from large parts of power finance, and a drastic reduction in the number of standalone energy traders. Enron's bankruptcy, however, was only the proximate cause of the market's collapse, since several power markets had excess power capacity, and several power producers were overleveraged.

The 2008 downturn threatens to marry the weakness of the post-Enron structures to a more general economic downturn. A contraction in commercial bank appetite for select power projects may be the least of the sector's worries.

Optimism about the private power sector's prospects rests on two assumptions. The first is that the financial services sector can respond as quickly and creatively to the present problems as it did from 2003. The second is that a more relaxed attitude towards power plant emissions will compensate for a recession-driven drop in demand for power.

The banks' lament

The events of the middle of 2008 have served mostly to hasten a contraction that has been a year in the making. Bankers at Project Finance's US power forum in January, seemed to relish the change in circumstances. The B loan market, which provided very real competition to commercial banks, had disappeared.

Underwriting commitments were lower, pricing and fees were up, and the mid-tier banks took on an outsized importance in getting deals closed. Developers, which had grown used to playing banks and the B loan market against each other, found their bankers much less friendly.

Two large acquisition financings came to market in the first quarter of 2008. EIF's $850 million Cogentrix acquisition financing and IFM's $870 million financing for its acquisition of Consolidated Edison's unregulated portfolio both encountered hurdles. Calyon's syndication of the Calypso debt was widely criticised for not sharing enough of the deal's underwriting economics. IFM had to step up when its partner, Allco, dropped out.

Commercial banks proved vital to closing the construction financings for Kleen Energy, an EIF-sponsored gas-fired plant in Connecticut, and Topaz, a Texas repowering for which Carlyle/Riverstone was the lead sponsor. The $740 million Topaz financing, led by Morgan Stanley with Dexia, ING and Natixis as co-leads, featured a hedge and high levels of equity, at $519 million. Goldman Sachs led the $1.015 billion debt financing for Kleen, but BNP Paribas, Dexia, HSH Nordbank, ING Capital, Natixis, Scotia Capital, UBoC and WestLB rounded out the bank group.

The latest phase of the credit crunch was the hardest one on European lenders. RBS, Fortis, Dexia, Natixis and ING, have been recapitalised, partially nationalised, sold or dismembered under distressed circumstances. Libor, whose 3-month dollar rate stood at barely over 1% in early 2004, climbed above 5% in 2006, and dropped below 3% earlier this year, then climbed again sharply in September.

Untangling the crunch-related capacity contraction from the contraction that typically takes place at the end of a calendar year is difficult. "Banks have very little room to work with this quarter," notes one banker. "They want to hit their budget to be sure of getting an allocation next year, but no way will they be able to go over." Clubs have been common in the US, although resistance from underwriting banks to flatter syndication structures lingered a little longer than in Europe.

Privately confident?

The most promising avenue for power sponsors is project bonds, whether privately placed or issued under Rule 144A. During the heyday of the B loan market, the restrictive covenants and minimum rating requirements, usually investment grade, for power project bonds made them unattractive to sponsors, especially when B loan providers became more accommodating of construction risk than institutional investors.

The market has become much more expensive, though it lacks some of the uncertainties associated with bank financing, particularly banks' insistence not only on receiving a margin over a floating benchmark, but an ability to reject or modify this benchmark, in the guise of market disruption clauses. Fixed-rate financing – if available – looks good by comparison.

There are some precedents – in the last two months two geothermal projects closed financings at above 9%. Nevada Geothermal closed a $180 million financing with TCW at 14% for its Blue Mountain project, while Raser geothermal closed a $10 million financing for its Thermo asset with Merrill Lynch at 9.5%. Meanwhile Illinois Power, an investment grade, regulated utility, borrowed ten-year debt at 10%.

These data points are far from reliable predictors of borrowing costs, since geothermal assets are small niche in the market, and Illinois Power, an Ameren subsidiary has a complex credit history and relationship with its regulations. But sponsors as large and experienced as EIF are looking to approach the bond market in 2009.

A rash of bond financings would not necessarily be bad news for banks, since many issues depend on banks for credit enhancement both large (say, a construction guarantee along the lines of ArcLight's Lea Power) and small (say, an interconnection letter of credit). Banks may also provide a construction loan to a project, which would in turn be refinanced with a project bond.

This last model has a long pedigree. In the 1990s, banks would extend construction loans to independent power projects, often with equity warrants attached, with an insurance company or pension fund lined up in advance to replace this. The method echoes the way banks today finance wind projects by extending short-term construction loans with a tax equity provider, often a financial or life company, signed in to refinance this debt.

"But the market has long since changed," as one US project lender noted. European and Asian banks moved in to provide long-dated bank debt, and will still do so for the right projects. The response from these lenders to the current crisis has been to tighten covenants, beef up cash-sweeping provisions and, yes, increase pricing and fees.

No more I in IPP

As developers require ever larger balance sheets to support equipment purchases and power marketing obligations, and banks concentrate on the largest clients, smaller players, as well as the larger pure generators, may start to look like attractive targets to larger integrated utilities. Independent power producer share prices have fallen relative to integrated utilities, and Exelon, with its now-hostile $6 billion bid for NRG Energy, is among the utilities to take note.

As deregulation fails to take root outside Texas and the Northeast, more distributors are taking back control of generation additions. Dominion Power has taken advantage of halting reregulation to take the lead in new capacity additions, both thermal and renewable. United Illuminating has formed a joint venture with NRG to build two new peaker projects in its theoretically deregulated home territory of Connecticut, and is looking to place $400 million to finance half their cost.

NRG's shareholders are contemplating Exelon's bid, and Reliant has said that it has hired Morgan Stanley to help it explore strategic options, polite shorthand for putting itself up for sale. Consolidation, which has been promised in the US power sector for nearly ten years, is again a market buzzword.
The main argument in favour of such mergers is the prohibitive cost of running a power and fuel marketing operation. Trading counterparties now demand greater amounts of cash as collateral against hedges, or liens on generating assets, which cut down on generators' liquidity needs but make secured lenders nervous. Nuclear plant development, even if it could benefit from federal loan guarantees, is a game for the richest generators.

The main argument against consolidation is the prohibitive length of time and uncertainty involved in gaining clearance for mergers. Even if state regulators have grown relaxed about utilities re-taking control of generation, federal ones could demand that merged entities divest assets, which undermines some of the rationale for a combination.

Funds and friends

The potential for divestments brings the power finance market back full circle, to the private equity and infrastructure fund industry. Libor has started to drift back down, though banks still have little use for it as a benchmark for funding costs. First Energy agreed to price a $300 million credit facility with reference to the price of credit default swaps on both the borrower and the arranger, Credit Suisse.

But recent news from the utility finance market offers grounds for optimism, Pacific Gas & Electric priced a ten-year bond at 395bp over the equivalent Treasury, compared to 600bp for Illinois Power, and Southwestern Public Service, an Xcel Energy, priced an issue at 515bp over. At these levels, infrastructure funds have little incentive to move into the lending business.

But funds like the power sector, even those formed ostensibly to take advantage of transport infrastructure. This interest is understandable, since Morgan Stanley Infrastructure, Alinda, Global Infrastructure Partners (GIP), Neuberger Berman/Lehman Brothers, RREEF and HSBC Infrastructure all have former project finance bankers with power experience among their management.

IFM bought ConEd's independent power portfolio, while Hastings and JPMorgan's IIF fund acquired several peaking projects from utility Black Hills. GIP, together with Fortistar, bought the Channelview power project out of bankruptcy for $500 million. Hastings and IIF IFM closed a $550 million loan with RBS to support the $840 million purchase, while IFM used even lower leverage and GIP and its partner have not yet put in place a long-term debt deal on Channelview.

These deals indicate that the funds have the cash and the patience to leave their mark on the power landscape, although without high gearing their returns may fall below some of their limited partners' expectations. Still, for specialised funds like those run by Tenaska, ArcLight and EIF, the competition may force them to concentrate on opportunities, particularly for new-build projects, where their expertise will tell more clearly.

Fuel for thought

Developers might be justified in their optimism about financial markets' resilience. More worry, however is likely to come from Washington DC. Developers hope that recession in the US will dampen lawmaker's enthusiasm for emissions regulation, which has cast a cloud over new coal plant construction.

The more paranoid developer will assert that the new US administration is likely, whether through emissions-trading legislation or its foreign policy, to cause a large spike in gas prices. So far, however, natural gas, which tends mostly to be used in the petrochemical and power industries, has been the victim of recession-inspired demand destruction.

But with utilities controlling the power capacity procurement process, and neither power nor fuel prices at the levels necessary to spur capacity additions, the independent power  sector could go back to being the small but lucrative adjuncts to the power business they were in the 1990s.