three fuels plus two business models equals one impasse
Life was a lot easier years ago when it came to building power plants. When a state or region identified a need for power, the local utility would build to that need. Depending on where the plant was built, the utility could choose coal, hydro, oil or nuclear power. Wall Street rarely had qualms about the risk, since the utility’s service territory monopoly and the ratemaking process ensured a captive customer base and hence a secure repayment source. The system may not have been least-cost, but it was surely reliable. About 20 years ago, things changed.
The Public Utility Regulatory Policies Act of 1978 (PURPA) and its progeny, the Energy Policy Acts (EPAct) of 1992 and 2005, established a second regime for power plant development based on competition, diversity and risk. The competitive power model was based on a foundation of contracts rather than regulatory compacts, of voluntarism rather than captivity, and of private risk-taking rather than indirect public funding of electric capital investments. The finance mechanism for the vast majority of non-utility construction was project finance, a regime that allowed lenders to assess the risks of individual projects (and dictate the level of equity required) on a free-standing, project-specific basis.
Two historical oddities influenced the nascent competitive power business. First, half the PURPA program was devoted to the encouragement and development of renewable energy. The new industry cut its construction teeth on geothermal, wind, solar, waste and small hydro projects-not your traditional utility fare. Second, while passage of the federal Fuel Use Act had essentially halted utility development of natural gas power plants, this was not the case for the non-utility developers, who over the next two decades built first gas cogeneration, under PURPA, and then combined cycle gas plants under EPAct of 1992. Utility construction was far less active during these two decades, given the collapse of the nuclear power option after Three Mile Island, the dramatic decrease in new coal development, and the already mentioned Fuel Use Act. Add to that a number of generation portfolio divestitures by utilities, and by the turn of the century, competitive power owned or controlled some 40 percent of domestic generation.
The competitive power sector’s dramatic collapse after California and Enron reintroduced the classic question that has dominated the sector for a century: how to finance what is arguably the world’s most capital-intensive activity. That question had two answers until only a few years ago: ratebasing (the utility model) and project finance (the non-utility model). The latter paradigm has taken a beating in recent years. Lenders are loath to put debt into new competitive power projects absent either long-term power purchase agreements or parental guarantees; and many of the non-utility superpowers of the 1990s are still repairing their balance sheets and credit ratings to deploy the equity necessary to build these new projects.
Almost inevitably, the utility rate base model has surged to a renaissance, promising a return to the good old days. The pitch seems compelling: we (the incumbent industry) have been building power plants for a hundred years; we are safe, reliable, familiar, and we won’t go bankrupt.
The non-utility generators responded in kind: our power plants (and track record) are equally safe and reliable. More importantly, and in stark contrast to the utility rate base model, not a penny of our losses has ever been passed through to ratepayers.
A second facet of this ongoing discussion is fuel choice. For the near term, the three dominant options are the same: coal (either traditional or IGCC), nuclear and renewables. Neither sector has a monopoly or even an advantage with any of these technologies. (While competitive power is often thought of as favoring natural gas and renewables, in fact the sector’s portfolio breaks out as 36 percent coal, 30 percent natural gas and 24 percent nuclear.)
As the nation’s reserve margins dwindle, critically in some parts of the country, the discussion as to who builds the next generation of power plants is well worth having. There is no one-size-fits-all answer. Each side holds roughly one-half of the generation in the United States. Region by region, state by state, service territory by service territory, and plant by plant, choices must be made as to whether these resources will be deployed through the competitive process, with the long term contracts necessary to support the investment, or through the long term utility rate basing of the investment. Given that the country is poised to spend many tens of billions of dollars on vital national resources that we will depend on and pay for over the next half century, a default answer based on either fear or nostalgia will not suffice.
Richard Lehfeldt is an energy partner with Dickstein Shapiro LLP, and Larry Eisenstat is head of the electric power practice. Contact them at email@example.com and firstname.lastname@example.org, respectively.