Ode to the Undercontracted Thermal Asset

By Eric W. Sievers, Baker & McKenzie LLP

Although power sector is recovering, changing market presents a challenge.

SOME BLAME THE END OF A WAY OF LIFE on her lack of a long-term commitment, cite her as proof that the IPP model is flawed, and scorn her for the wrecked lives she has, it is claimed, left in her wake. We all know her; many of us even painfully parted ways with her ourselves under unfavorable circumstances. Ironic it is, then, that she now has more suitors than ever.

The undercontracted combined cycle facility in question is close to the intersection of a 345-kV line and a 20-in. pipeline, has a heat rate in the low 7,000s, had a lean build cost per kilowatt, and entered commercial operation, give or take a couple months, coincident with the Enron bankruptcy. Half or more of her capacity remains free from long-term power purchase arrangements.

Using the acquisition of our hypothetical combined cycle as a proxy, this article surveys a recovering power sector within a fundamentally changed market. The shaping trends and opportunities in the U.S. power sector are no less bold and powerful today than during any zenith of the past 25 years, but novel actors, approaches, and risks drive these opportunities and demand revisions to tried-and-true business plans. By no means exhaustively, we survey below seven evolving elements of the post-insolvent U.S. independent power producer (IPP) sector and outline impacts each could have in coming years.

1. Rate Base Expansion

The strengthened ability of traditional utilities to push projects through state commissions means local utilities have become natural buyers of distressed, especially uncontracted or solely utility contracted, assets in their service areas. The California crisis, the East Coast blackout, and, less pertinent to real world situations but quite effective in public discourse, dozens of project defaults within and outside the bankruptcies of Enron, NRG, Mirant, and Calpine have eroded public enthusiasm for free-market generators, prodded state regulators to willingly sacrifice attainable efficiency for the sake of questionable reliability, and created a newly unequal playing field between utilities and independents.

While traditional utilities will likely maintain much of their current clout over the next few years, there are two trends to watch closely. First, we are encouraged by signs that regional transmission organizations (RTOs) are bringing some needed new discipline and transparent pricing to the sector, in both cases meaning that a nonutility acquisition remains a possibility. Second, primarily for reasons we discuss later (in items 4 and 6), but also due to innovations such as Internet over power lines, we would not be surprised to see a wave of the rumored TXU-like spin-off transactions impact investor-owned utilities.

2. Commodities Hedges

Likewise, we are encouraged by the market impact of commodities hedge agreements, primarily the five- to seven-year power purchase agreements that J. Aron and Morgan Stanley (with other financial players also emerging) deploy so effectively. We do not expect similar impact from or expansion in the use of (albeit rare) 10- and 15-year gas hedges, and we do not discuss them further in this article.

Our combined cycle is almost certainly located in an area amenable to a commodities hedge. Accordingly, if overtures to the local utility or the unregulated utility power marketers of the world do not yield favorable prices, and, frankly, even if they do, we would hope to engage the hedge providers for indicative quotes and some market intelligence, either of which, in our experience, might be unique to that hedge provider.

Quite simply, the high credit ratings and quick response times of the hedge providers are boons to deal structuring, especially during limited windows of exclusivity. While the short tenors of hedges ensure a brisk refinancing business in the near future, traditional offtakers are also scaling back their own commitments.

Our expectation is that additional hedge providers will enter the market in the next few years. Their responsiveness and high ratings will, effectively, unlock hundreds of millions of dollars of generator revenue that would otherwise have been lost or gone into the pockets of utilities (due to lower capacity payments) and lenders (due to higher interest payments). Accordingly, in a nonutility acquisition, a commodities hedge might have an important role.

3. Liquid RTOs

If our combined cycle does not become fully contracted, a financial buyer (likely one that is also a commodities hedge provider) or equity risk taker might actually implement the facility's original business plan, namely, use its low heat rate to make money off of day-ahead and spot markets, the so-called Day 2 RTO elements.

While some recent Day 2 impacts, such as the Commonwealth Edison capacity market crashing under PJM Interconnection and Midwest Independent Transmission System Operator's Day 2 launch leading to midnight dispatches of peaker plants, raise questions about core efficiency, we believe that the Day 2 markets overall are pushing many areas toward more in-merit dispatch.

Since we also believe that the liquefied natural gas supply (and, later, Alaskan pipeline gas) coming on-line over the next couple years will lessen gas price volatility, especially in the South, the merchant combined cycle could reappear, although we doubt that it will become the norm.

4. PUHCA Repeal

Barring reactionary federal legislation restricting foreign ownership of infrastructure, it is clear to us that repeal of the Public Utility Holding Company Act if 1935 (PUHCA) will result in a more liquid market, either because our combined cycle will be purchased by a foreign buyer or because part of the transmission and distribution system will be purchased by a foreign buyer.

While our prediction is theoretical at present, we have been meeting with Asia-Pacific and European generators, utilities, and financial players who are already deploying resources to purchase a project or two, citing one actual example, or get a few more commitments from low-yield institutional investors, citing another example, before making offers on tens of billions of dollars of regulated businesses.

In other words, especially if our cogen becomes fully contracted and can secure an investment grade rating, we believe it likely her ultimate owners will be foreign. Also, we note that some foreign buyers will put projects on their balance sheet and, thus, can, in some exceptional cases, lower their debt costs to below the London Interbank Offered Rate (LIBOR).

5. Non-Bank Debt

The ultimate illustration of market change in the past five years is contained in the fact that the traditional project finance banks are less likely today to want to loan a dollar to a project than to earn arranger fees, be a facility's primary offtaker, or hedge LIBOR risk.

On the heels of the Texas Genco, La Paloma, and Wolf Hollow transactions (ignoring previous greenfield Term B financings), actual lender merger and acquisition dollars today increasingly come via the Term B and Term C markets. In these financings, an arranging bank presents the project to two ratings agencies. Within a month, the ratings agencies issue preliminary ratings for Term B or Term B/Term C debt. Within a few weeks after that, the financing closes. Because the Term B players (risk/return investors in the LIBOR+250 range for generally well-contracted and -performing operating assets) and Term C players (risk/return investors looking for LIBOR+450 and, in the case of hedge funds, eventually swapping debt for equity) by definition have money looking for deals, their scrutiny of projects is limited, with the formal ratings and personal relationships with arrangers taking the place of such scrutiny.

Likewise, because the arranger's principal concern is financial closing, finance documentation has become standardized (in our opinion, appropriately so), and the process cannot, in most cases, be stalled due to problems with a credit committee, since no individual lender is crucial to the deal.

The Term B/Term C market has its own downsides, some being that sometimes the bank's incentives are not aligned with the sponsor's, the term is only for five to seven years, and some lenders, especially in the C tranche, are prepared for project defaults. Nevertheless, Term B notes may be the dominant non-recourse project finance vehicle for domestic power project sponsors for the next several years. Ironically, the recovering market is the biggest threat to its expansion, as improving pro formas and offtaker credit ratings threaten to price some power deals coming to market under the likely minimum thresholds of normal Term B lenders.

6. Bank Innovations

For a suggestion of trends outside the Term B world and in the investment grade world, one need only look to the current revolution in toll road finance. When the long-term Chicago Skyway lease brought Chicago $1.8 billion in 2005, the novelty of the transaction was shocking. Moreover, when the acquisition bank debt was taken out with a private placement of 12- to 17-year notes with a LIBOR spread of 28 to 38 basis points, a long-term credit enhancement mechanism that resolves refinancing risk, and mezzanine debt with a spread of 250 to 300 bps, Project Finance reacted with a 2005 deal of the year award.

However, when the Indiana Toll Road lease drew a winning bid of almost $4 billion in early 2006, backed by a nine-year bank debt arrangement that fixes interest at 3% per year in the initial years, it probably marked the start of a wave of U.S. infrastructure privatization.

While we, unfortunately, do not expect the Indiana Toll Road model to find much application on the generator side of the U.S. power business, certain other aspects of the business, such as transmission, would appear well-positioned to benefit directly.

7. Renewable Energy

Although the 2005 energy legislation and RTOs make the Public Utility Regulatory Policies Act of 1978 appear largely irrelevant (on the one hand because steam patsies now ruin eligibility and, on the other hand, because competitive markets obviate the idea of avoided costs), we see a potentially bright future for cogeneration projects with at least part of the renewables vanguard.

Even before the 2006 State of the Union address, a number of 100-plus million-gallon-per-year ethanol facilities were under active development, even in "destination" locations such as New York and Texas. Ethanol facilities are energy intensive baseload facilities requiring both steam and power. Some ethanol projects anticipate inside-the-fence cogens, and in some cases the rush to get plants in service is deferring these plans until the 2008–2010 timeframe. Less thought has, in our opinion, been put into researching the placement of ethanol facilities near existing cogens. Accordingly, if our combined cycle is located near a railroad, and surrounding land is inexpensive, a case can be made for matching it with an ethanol facility.

Conclusion

Over the period through 2008, a mix of domestic and foreign sponsors will compete for a large number of U.S. thermal generation assets. Many of us hope, after weathering the exhausting and frustrating early years of the decade, that the current recovery is a tide that will lift all boats. However, the divergent cost of capital requirements, appetites for risk, and levels of reliance on and access to the debt markets of the late decade power players should remind us all of the need for investors to understand the structural changes in today's market and the need for investment strategies capable of withstanding both business cycles and the fluid nature of competition in the industry.