Beneath the crystal-blue waters of the Caribbean Sea, coral reefs once vibrant with color are turning white and dying. Their demise, evident for more than a decade, is disquieting not only because it shows the disruption of a fragile ecosystem and the decline of some truly splendid snorkeling destinations, but for its potential effect on U.S. environmental policy.
What’s killing the corals is not entirely understood, but researchers have identified temperature changes as a culprit. Temperatures are rising globally, in the oceans as well as the atmosphere. But more troublesome for the corals, climate changes are disrupting ocean currents that keep Caribbean water temperatures relatively stable and cool—and incidentally, keep Northern Europe warm, according to a data from various research groups, including NASA.
In May 2006, the U.S. National Marine Fisheries Service added two types of Caribbean coral (elkhorn and staghorn) to the list of threatened species protected under the Endangered Species Act (ESA). Except for Puerto Rico and a few other islands, most of the Caribbean Sea lies outside U.S. jurisdiction. But the corals’ plight could affect many U.S. companies nonetheless.
The ESA requires federal agencies to ensure their actions do not jeopardize any listed species, or adversely affect their critical habitat. This directive could translate into changes in environmental and investment policies, depending on how the law is enforced. In the short term, it adds legal ammunition for plaintiffs in climate-change lawsuits, and represents another signal that greenhouse-gas regulation is coming to America (see sidebar “Legal Heatwave: Courts & Climate Change”).
These trends pose a dilemma for U.S. power companies and regulators. To meet rising electricity demands over the next decade, the American market needs more than $100 billion worth of new generating capacity, and billions more in upgraded emissions controls and life-extensions at existing plants. But utilities and their underwriters are beginning to think seriously about how future GHG restrictions will affect strategic plans.
“Carbon risk has to be factored into any decision going forward,” says Dennis Murphy, vice president and COO, PPL Generation in Allentown, Pa. “We expect to be participating in the discussion of what the regulations and controls might be, and we are assessing carbon constraints at a corporate level.”
PPL considered such factors, for example, when deciding to spend $1.5 billion between now and 2009 to install scrubbers at its two coal-fired 1,500-MW plants at Montour and Brunner Island in Central Pennsylvania. And in June 2006, it joined the FutureGen Alliance that is seeking to develop a near-zero emissions power plant.
At the same time, though, PPL and other power companies in many U.S. states are pursuing an investment strategy that relies significantly on new coal capacity, particularly in market regions dominated by higher-cost gas-fired power (see sidebar “TXU’s Coal Bet”). Confidence in pulverized coal is wavering, but whether it might fade like the color of Caribbean corals remains to be seen.
Regulatory risk has been an important factor for the U.S. power industry for decades. Indeed, it was one of the main factors that sparked deregulation and the rise of the independent power-development industry in the 1980s and 1990s.
Specifically, power prices were increasing because utilities were not building enough power plants to maintain comfortable reserve margins. Their caution was understandable, as many companies were hurt badly by nuclear cost-recovery disallowances in the aftermath of the Three Mile Island accident. Risk-averse utility shareholders shunned companies that had assumed significant plant-construction risks, and the fallout from that era still permeates the utility landscape today.
However, utility companies have learned and re-learned many lessons in the past two decades, and today they are eager to invest in new power capacity—in part as a rate-base building endeavor, and in part because they recognize the danger of relying too much on any single fuel source. The dominance of gas-fired plants during the 1990s construction wave has exposed many utilities to uncomfortable levels of fuel-price volatility.
“We believe it is in the best interests of our company, and the country as a whole, to have a diverse energy base,” says Skiles Boyd, vice president of environmental management and resources at DTE Energy in Detroit. “In the long term, diversity is probably the biggest factor in our decision-making process.”
Environmental issues, however, are adding greater complexities to company strategies for achieving fuel diversity. DTE, for example, relies mostly on coal, natural gas and uranium to meet its power demands—already a diverse mix. But stricter environmental requirements have compelled DTE to commit more than $1.3 billion to install low-NOX burners at its gas-fired plants, and scrubbers and selective catalytic reduction (SCR) equipment at its coal-fired plants. The company’s biggest investment involves SCR retrofits at three of four 780-MW coal-fired units at its Monroe facility. Over the next decade, DTE expects to invest about $2.2 billion to comply with the Clean Air Interstate Rule (CAIR) and new mercury standards.
“Our strategy is to build what we need,” Boyd says. “We are focusing on emissions-control equipment to meet standards to the extent we can, and we will supplement that by buying emissions credits in the market.”
DTE is in a relatively comfortable position, both in terms of fuel diversity and readiness for tighter environmental constraints, in part because the company staked out a leadership position more than a decade ago, when it joined the Department of Energy’s Climate Challenge program in 1995 and began systematically reducing its carbon footprint.
“Our actual emissions are at about 1990 levels right now,” Boyd says. “Our carbon position is pretty good, because we ramped up operations at [the Fermi 2] nuclear unit since 1990, and we have an unregulated subsidiary, DTE Biomass, that offsets our emissions by capturing landfill gas and converting it to energy.”
However, not all utilities find themselves in DTE’s position. Many companies are even more heavily dependent on coal than DTE is, and many of the rest are hoping to build more coal-fired capacity in the next five years. At least 150 coal-fired units are now being developed in the United States, and most of them are pulverized-coal (PC) units.
While it’s true that PC plants pose risks and costs for complying with future carbon constraints, many utilities see little choice but to invest in boilers now, and wait to see what happens with carbon constraints.
“When carbon sequestration becomes a requirement, the cost will be filtered through to the market,” says Stephen A. Stolze, a managing director with Black & Veatch’s enterprise management solutions division in Long Island. “It will have different impacts on different technologies, but it’s naïve to think coal will become a less-important fuel in the near term, given the limitations of the alternatives.
Thus, the next wave of power-plant construction seems certain to be dominated by PC plants—a trend that nevertheless seems counterintuitive in the long-term context of ever-tighter environmental constraints.
“From a sustainability perspective, increasing reliance on coal is a risky strategy,” says Michael Zimmer, a partner with Thompson Hine in Washington, D.C. In addition to carbon constraints, he notes growing transportation costs and uncertainties. Coal shipments have been interrupted multiple times in recent years, due to line congestion and other factors.
In an effort to catch up with demand growth, rail companies are investing in new lines, such as a $100 million project by Union Pacific and BNSF to build 40 miles of expanded line capacity to carry Powder River Basin coal from Wyoming. These investments will help, but adding 150 new coal-fired units all over the country, along with retrofits that extend the operating lives of existing plants, could stress an already strained rail system.
“More utilities need to be developing portfolio approaches on generation, to use a blend of supplies that will keep delivered prices stable,” Zimmer says. “Utility credit quality is hinging on the issue of diversity—the rising cost of fuel and what you are doing to manage it.”
The risk for power generators is that they will be caught relying too heavily on a fuel or power-generation technology that becomes impaired in the market, whether because of supply problems or climate concerns. Such risks are difficult to manage, because competitive markets and regulators alike reward low-cost producers in the immediate term and punish high-cost ones, even if their investment decisions are the most prudent and beneficial for ratepayers in the long run.
For their part, ratepayers don’t seem to care much about climate change, but then neither do they care about the effects of criteria pollutants until they are directly affected by asthma or smog. In each case, ratepayers accept the fact that protecting the environment bears a cost, and they expect utilities to pass that cost along to them. “The reason ratepayers aren’t in the debate is because energy is a minimum-price play,” says Michael Valocchi, a senior managing director with FTI Consulting in Philadelphia. “But they expect American corporations, including utilities, to be good environmental citizens.”
Utilities might find greater support from ratepayers if they actively promoted a forward-thinking vision. Ratepayers readily understand the value of research and development, especially if it is presented as part of an overall strategy for managing energy-price risks. But the real challenge of environmental leadership is not in developing technology or promoting it to customers, but in mustering the political will to socialize some share of the investment cost.
“PUCs are willing to run utilities almost into bankruptcy to keep rates down,” says Doug Dunn, a partner with Milbank, Tweed, Hadley & McCloy in New York and chair of its utility practice. “That endangers future generation investments, but the lesson has never been learned by the PUCs.”
However, facing the complex challenges of improving supply diversity while also protecting the environment, some utilities and rate regulators are adapting the regulatory compact to support a long-term technology vision.
In April 2006, the Ohio PUC granted American Electric Power’s (AEP) request to recover nearly $24 million in pre-construction costs for the company’s proposed integrated gasification combined cycle (IGCC) project. This pay-as-you-go approach is relatively novel in the electric power industry, but AEP’s experience offers hope for power generators seeking to pioneer the next generation of power-generation solutions. In Minnesota, the state PUC is reviewing a proposed power-sales contract that would require Xcel Energy to buy power from an IGCC facility proposed by Excelsior Energy in Northeastern Minnesota. The agreement would allow Xcel to pass the technology premium through to ratepayers. And DTE is contemplating investments in nuclear and IGCC projects, while grappling with the challenge of undertaking next-generation investments without overburdening shareholders with technology risks.
“With large investments it would be advantageous if we could take our plant to the commission and have them approve cost-recovery up front,” Boyd says. “It certainly would take away some of the risk. Periodically we have that conversation with the commission, but we haven’t asked for a specific ruling.”
Utility commissions naturally are skeptical about rate-recovery requests, especially novel ones that ask ratepayers to bear R&D costs that will benefit shareholders. But the pay-as-you-go idea might gain momentum as part of state integrated resource planning (IRP) proceedings, or during project-permitting processes to obtain certificates of public convenience and necessity.
“Regulators won’t like the idea, but it has to be part of the conversation up front,” Dunn says. “Otherwise, investors won’t put money into something that must face a prudence review at the end.”