Why any bank would lend to an independent power producer plant in the US can be puzzling. The industry has experienced a spectacular boom and bust cycle since at least the 1980s; one that has boosted and bankrupted the likes of Enron and PG&E National Energy Group. Banks, however, have long since given up bending their terms to appease favoured independent power clients. Gone are the monoline-wrapped bank loans and institutional B loans of yore, and in are covenant-tight vanilla financings for contracted plants boasting investment grade offtakers.

The deals that closed in the conventional, gas-fired, power sector in 2010 have shorter tenors, explicit offtake agreements and pricing that, while down slightly from 2009, is still higher than where it was before the 2008 credit crunch. Only two completely new plants were financed this year: Mirant’s 760MW Marsh Landing and Pure Energy Resources’ 512MW Bayonne, and Marsh Landing was a replacement for an existing facility. Bayonne was notable for having an element of merchant risk though, for the most part, power finance bankers have avoided drawing attention to the merchant elements of their transactions.

“Power market prices have sunk so deeply through surplus capacity, low gas prices and regulators’ tilting of competitive markets that no one will finance a new merchant power plant for the foreseeable future,” says Jay Worenklein, a partner at Bingham, former global head of SG’s project finance group, and founder and former chief executive of US Power Generating.

Consumption of energy in the US dropped 6.8% between 2007 and 2009, according to the US Energy Information Administration. This is the second largest drop in consumption since 1949, second only to the 9.7% drop between 1979 and 1983. But this latest decline in demand occurred just as many thought the market was finally recovering from the massive overbuild of the late 1990s. This, coupled with growth in renewables and on-going load auctions around the country, could potentially push the need for new conventional electricity generating capacity in the US out as far as 2020.

“The new-build market in the US is dead for the time being,” says one market participant who works on power plant financing deals. They acknowledge that some replacements will be built but emphasise that many parts of the US continue to have excess capacity.

Financing firms up

Financing terms are improving despite the bleak demand outlook. Spreads, which peaked at around 350bp over Libor in 2009, have come in to as low as 250bp over Libor for the fully contracted Marsh Landing. Tenors, though, remain short, with GWF Energy’s Tracy plant expansion securing the longest since the crunch, at construction plus 10 years. Structures are likely to remain tried and tested, with most developers finding financing through either club or syndicated bank loans or the private placement market. On the whole, market participants do not expect to see pricing go much lower or tenors get much longer for some time.

Marsh Landing, developed by Mirant, is a good example of the current market dynamics. Royal Bank of Scotland, Royal Bank of Canada and WestLB lead arranged the $650 million financing for the 760MW simple cycle natural gas fired plant. The debt was split into a two-tranche $500 million term loan and $150 million in letters of credit. The term loan’s $150 million A tranche has a construction plus five-year tenor and priced at 250bp over Libor while the $350 million B tranche has a construction plus seven-year tenor and priced at 275 over Libor. The average debt service coverage ratio for the project is 1.4x. The developer has a 10-year power-purchase agreement (PPA) with Pacific Gas & Electric (PG&E) for the plants for capacity.

The plant is a replacement for the 50-year-old 680MW Contra Costa county power plant that will be decommissioned when Marsh Landing opens. In addition, the open­ing of the Trans Bay transmission cable (see Deal Analysis above) means the plant will also be feeding the city and county of San Francisco, where Mirant’s 362MW Potrero Generating Station will be decommissioned by 2014.

California remains one of the best sources of financeable power purchase agreements, whether for gas, wind, solar, or geothermal. The $410 million conversion of GWF’s 169MW Tracy peaker to a 314MW combined cycle plant illustrates the attractions. Bank of Tokyo Mitsubishi-UFJ, GE Energy Financial Services, ING and Scotia Bank were joint lead arrangers of the $305 million loan and $105 million letter of credit that priced at 250bp over Libor. CoBank, Dekabank and Helaba participated in the financing.

The transaction is notable because the banks were willing to offer the developer a slightly longer tenor of construction plus 10 years. One New York-based project finance banker noted that the financing was unusual in that two of GWF’s operational combined cycle plants, the 95MW Hanford and 97MW Henrietta facilities, were used as collateral for the loan. The inclusion of the existing peakers indicates that lenders may not have been as comfortable with the Tracy credit as the pricing and tenor hinted. GWF is a joint venture of PSEG and Harbert, while Tracy has a 10-year power purchase agreement with Pacific Gas & Electric.

Market participants predict that most conventional deals will be ownership shifts, refinancings or acquisitions going forward. For example, deals like Constellation Energy’s court-approved acquisition of Boston Generating’s 2,950MW operational gas-fired portfolio for $1.1 billion are likely to be more prevalent in the market. The vast majority of new plant financings will be contracted replacements or minimal expansions of existing plants.

The merchant aspect

Pure’s Bayonne peaker is the exception to the rule. The fact that the plant, an entirely new facility with a small element of merchant risk, was successfully financed is attributed by most bankers to the fact that it sells to the New York City ISO. For the most part, merchant risk is still a non-starter in US power project finance.

“100% merchant is not financeable and I don’t see it being financeable anytime soon,” said a project finance banker who works on power transactions. During the latter part of the past decade, banks knew the risks but often worked with developers to offset those issues with hedges and tolling agreements when PPAs were not available. Unfortunately, many of those hedges collapsed with fuel prices and the investment banks that provided them, proving to be essentially counterparty exposure to the banks for the developers. That before Enron’s collapse they frequently financed naked merchant risk would come as little comfort. Today, both lenders and sponsors are weary of taking excessive risks in the market, and Pure represents a small step forward in their countenancing merchant risk.

The 512MW plant is a simple-cycle natural gas fired peaker located on industrial land on the New Jersey side of New York harbour. ArcLight Capital and Hess Corporation are the project sponsors and contributed a total of $270 million in equity, split evenly, to the project. The plant uses eight Trent 60 WLE turbines that are manufactured by Rolls Royce Energy Systems and is connected to the Gowanus substation by a roughly 10.9km, three-phase 345kV submarine cable manufactured and installed by ABB.

Credit Agricole and WestLB led the $422 million syndicated bank loan for Bayonne. Investec, GE Capital, LBBW, Intesa Sanpaolo and Societe Generale took tickets on the debt, which was split into a six-year plus construction term $370 million construction term loan, a $10 million working capital facility, a $19 million debt reserve letter of credit and $23 million in additional letter of credit facilities to cover construction and interconnection costs. But the debt priced at 325bp over Libor (it will step up 25bp twice to 375bp over the life of the debt), 75bp higher than Marsh Landing, despite both deals closing within a month of each other, largely on account of its merchant exposure.

Hess’ trading group is managing the plant’s merchant risk for the duration of a complex 15-year offtake agreement. For the first six years, both sponsors will buy 100% of the plant’s capacity, split ArcLight 37.5% and Hess 62.5%. In year seven, the amount they purchase will step down to 75% of capacity, at the same ratio. The amount will continue to step down for the remainder of the offtake agreement, going to 50% in year eight and 25% in year 11 before reaching zero at the end of the offtake agreement in year 15. After that, the sponsors are betting on continued strong demand for electricity from NYISO Zone J. The deal is also notable for a power fund, ArcLight, being accepted as a financeable offtaker, though its lack of track record might explain part of the pricing premium.

Various sources who worked on the deal say they are not concerned about the merchant exposure for two reasons. One, the debt should be repaid by year eight, though most participants expect it to be refinanced before that, and, two, the plant’s location in the New York City ISO. Still, the sponsors paid another 75bp over Libor for the project’s merchant risk despite the offtake agreement and inherent guarantees of the New York market. If anything, the deal signals that, while bankers say they are not willing to take merchant risk, they actually are – for a price – though the debt was barely covered in syndication, at 1.14x.

Gas filled future

Those US conventional power plants built in the coming years will almost certainly be gas fired. Gas prices are at their lowest level in years and are expected to remain low as the development of various shale gas fields ramps up, and nuclear’s lengthy approvals process and coal’s environmental red flags mean construction of both types of facilities will be few and far between. These factors combined with other market forces make gas-fired power plants mighty attractive to both sponsors and developers.

“The market will continue to invest in conventional power,” says Trevor d’Olier-Lees, director of US utilities, power and project finance corporate and government ratings at Standard & Poor’s (S&P). “It will be contracted and mostly gas.”

The price of a natural gas 10-year forward contract has fallen by more than half to an average of $5.80 to $5.90 per MMBTU (one million British thermal units) today since June 2008, according to S&P. The rating agency also reports that price curves have levelled off for the next 120 months. Increased development of domestic natural gas deposits, such as in the mid-Atlantic’s Marcellus shale, has the potential – though increased shale gas extraction faces its own environmental hurdles – to keep US gas prices low. Combined, these factors make gas-fired plants extremely attractive to developers.

Lenders, while not necessarily optimistic about the US conventional power market, do foresee a pipeline of deals. No one expects a return of the boom times of the past decade but, on simply replacements alone, market players predict one or two new-build, gas-fired conventional power plants per year. Asked what impact renewables would have on conventional power, and many see them actually increas­ing the need for peakers and other back-up facilities to fill in when the wind does not blow or the sun shine. There is more than $1 trillion in unused capital lying around, but finding suitable opportunities will be the difficult part. n