Projects sprout in the United States and overseas, pushing the limits of grid capacity, turbine manufacturers and available sites.
Merchant power plants are emerging en masse to address the growing electricity needs of the United States and other countries, thanks to deregulation and fearless developers. While some plants are built to replace older, less-efficient utility-owned units, others would serve demand growth. Still more are planned as niche-oriented peakers - ready to supply the grid when marginal prices rise high enough. Ancillary services might offer another niche.
The bottom line is that the U.S. market is hot, as are others.
"With deregulation and the [number of] older facilities that will need to be replaced, the domestic U.S. market is much more fluid than it looked like it would be a few years ago," says Jeff Leichtman, a spokesman for Bechtel Enterprises in San Francisco.
Regardless of the purpose of these plants - most are still on the drawing board - they represent a stunning total of combined megawatt capacity. As of late October, developers had announced plans to build 109 plants in the United States to generate 56,368 MW, according to the Electric Power Supply Association of Washington, D.C. And EPSA's list isn't comprehensive.
How many of these projects will clear licensing hurdles and actually break ground? Will fuels and turbines be available to power these plants? Are there sufficient links to the transmission grids for these enterprises? And will banks finance the multi-billion-dollar cost of the proposals?
Only time will answer all these questions, but it's clear that the variables pose a formidable counterweight to the plans of developers. The uncertainties also suggest that during the coming decade, a shakeout will yield a small pool of major, integrated players, some developers say.
What may be most important about this rising wave of proposed merchant power plants is that they promise low costs and efficient designs. Plant owners expect to be free of most of the constraints imposed on independent power producers prior to deregulation. Therefore, developers say, the market for merchant power plants has yet to be defined.
"The 50,000-plus MW [new capacity currently proposed] seems like a big number, but there is 750,000 MW installed in the United States, and 45 percent of that capacity is over 25 years old," points out Ron Walter, senior vice president of business development for Calpine Corp. of San Jose, Calif. "A recent survey indicated that by 2015, about 90 percent of this [installed] capacity is going to have to be replaced. If you add to that the increase in demand of some 13,000 MW to 15,000 MW per year, you'll have to replace a million megawatts in this country," he adds.
"So anybody's prediction of what's being planned is really small compared to what has to be done."
Red Tape is Loosening
Led by pioneers like Massachusetts and California, many state utility commissions are reviewing the first wave of merchant plant proposals within those jurisdictions where such reviews are required. While the regulatory process varies from state to state, the common denominator is a trend toward a comparatively more rapid, less onerous process. California, which has a two-step process for approving plants - a notice of intention followed by an application for certification - doesn't necessarily have the fastest regulatory apparatus in the nation. It can take as long as two years to site a plant there, say developers. However, the state is favoring some types of plants over others by offering exemptions from some filing requirements. "With deregulation, any project that's gas-fired and the result of competitive negotiation, there's an exemption; and there are other exemptions," says Roger Johnson, manager of energy facilities siting at the California Public Utilities Commission. (See sidebar, California Certification: Still a Two-Step Process?)
Developers are willing to slog through the paperwork, despite the prospect of the task.
"A bit of the character of California is that we like to think of ourselves as leaders in new ways of doing business, but at the same time we have a heightened environmental awareness, which creates its own bureaucracy," says Walter. "The state wants to take into account not only regional but also local concerns, so there are a whole bunch of folks for whom we have to answer questions."
Massachusetts, too, has been labeled a state with a thorough, if not complicated, procedure for approval.fn1 But Janet Gail Besser, chair of the Department of Telecommunications and Energy, reckons that the process is nonetheless relatively rapid: "We take about nine months to site a plant," she says.
Other states help developers fly through the process. In Tennessee, Enron Corp. applied for a merchant plant in June and broke ground by November, according to Mark Palmer, public relations vice president at Enron's Capital & Trade Resources division in Houston.
Some states take a hands-off approach to merchant plants. In Illinois, for example, "there is no certification process for merchant power plants. They just need to comply with local zoning and EPA regulations," says Bill Riley, chief of the electric section of the Illinois Commerce Commission's energy department.
Pennsylvania has the same approach. "All you have to do is talk to PJM [the tristate Pennsylvania-New Jersey-Maryland electric grid authority] for its connection standards and then it's just the air, water and ground quality permits," says a source who asked not to be named, at the Pennsylvania Public Utility Commission's Bureau of Conservation, Economics and Energy Planning.
Of the states in the major regional markets, Texas is the fastest for regulatory approval, confirms Joe Bob Perkins, the CEO of Houston Industries Energy Inc.'s Wholesale Energy Group in Houston. A state-by-state comparison of the difficulty and time required for approval would need to encompass more than half,fn2, of the 50 states, where proposals are on the table or under construction.
Unmet Demand Spurs Plant Explosion
The merchant plant boom has been driven in large part by the failure of existing utilities to augment generating capacity to keep up with demand. The gap between existing capacity and demand has at times caused some surprising spikes in the electricity market. "The prices we saw this summer in the Midwest show the need for peak capacity. There were a few very short-term deals at $7,500-per-megawatt," says Palmer. "It was a hot day and nobody had any capacity. Some plants were down for scheduled maintenance and some were down because of storms.
"We've had eight or nine years of solid economic growth and not a stitch of new generating capacity in the Midwest, a recipe for trouble. It was a very strong signal that we have to open both wholesale and retail markets," he says. "It's like they're standing in the middle of the highway. You have got to get to one side or the other."
In New England, the first major regional U.S. market for merchant plants, the combined capacity of proposed plants is said to be equal to, if not twice, the installed capacity of the region.
"I've seen some of the data on the proposals in New England, and it's ridiculous; there seem to be a lot of people with same ideas," says Dennis Higgins, a pipeline company analyst at Morgan Stanley Dean Witter in New York.
Such a plethora of competing projects spells disaster for the Johnny-come-lately. While New England unquestionably needs new, efficient generating capacity, it is also in dire need of more substantial electrical transmission infrastructure and more gas pipelines.
"There are a lot of proposals out there, but a lot of people don't have sites ¼ or permits yet, and New England is not an easy place to site," says William Rockford, managing director of the Global Power Group at Chase Manhattan Bank in New York. "So the 30,000 MW [being proposed] really comes down to 5,000 MW maximum, not including the refurbished units."
Developers face a number of physical hurdles to site a plant once the question of market need is answered. "The two critical path items are transmission availability, or the capability to interconnect into the existing grid, [and] the air permitting process and the availability of water," says Paul Champagne, vice president of business development at PP&L Resources' global division in Fairfax, Va.
Indeed, the cost of investing in new or enhanced links to the transmission grid may prove to be a major factor in discouraging a number of otherwise financially sound merchant plant proposals.
"There are a couple of limiting factors to the growth of merchant power plants. One issue in New England is the impact of a proposal on transmission availability," says Besser.
Still, new gas pipeline proposals are arising in parallel with merchant power plant proposals in some states, like Massachusetts, where there are two new pipelines being developed, Besser notes. The Portland NGTS (www.pngts.maine.com) and the Maritimes & Northeast (www.mnpp.com) would each transport natural gas south from Atlantic Canada to Dracut, Mass. Each won certification from the U.S. Federal Energy Regulatory Commission in 1997. A third proposed pipeline, the North Atlantic (www.north-atlantic-pipeline.com), was put on "inactive status" in February at the FERC.
Several project developers concur that a nexus of gas pipelines and electrical transmission line access marks a key to success. Similarly, however, hardware may prove to be a short-term limit to growth for some project developers.
"Gas units up to now have been pretty cheap, but since everybody is looking for gas turbines, costs will go up," says Rockford. "If vendors can raise prices, that would have an adverse effect."
Recent reports indicate that gas turbine makers like General Electric Co. and Siemens A.G. have backlogs into summer 2001.
"GE has said that if you go to the secondary market for turbines, you shouldn't expect the same kind of warranty," one developer claims, alluding to the possibility that turbine demand might create a secondary market and somehow void standard warranties. Some developers say that their place in the order line with the turbine makers gives them a competitive edge.
"Calpine has 40 engines on order, or rights in the manufacturing queue, with a gross output of 8,000 MW," Walter says. "That puts us ahead of the curve...so that we'll be outfitted through 2001 or 2002. Others will feel the pinch."
Apart from site-specific limits to growth, the ability of a merchant generator to compete in the increasingly integrated U.S. power market calls up another set of variables that will determine which companies will be winners over the mid- to long-term.
"The day is coming when the small independent power generator will be an endangered species, looking for different ways to survive and looking for protection," says Perkins. "What is needed in this new market is the ability to combine top-tier [gas and electricity] trading and marketing capability with power generating assets. Otherwise you are a single plant out there by yourself as a price taker, not in control of your own destiny."
The Money Is There
Financing merchant power plants doesn't seem difficult in the current market.
"What we're finding is that the financing is very robust," says Champagne. Among banks that are active in the sector are Chase Manhattan, Credit Suisse First Boston, ING Barings, Toronto Dominion and Union Bank of Switzerland.
Unlike traditional project-financed deals of the past, where most of a plant's capacity had to be covered in long-term power purchase agreements, merchant plants are being financed without such guarantees.
Houston Industries recently closed the financing on what it described as one of the first "pure" merchant plant deals in the country, in which there were neither power purchase agreements nor gas feedstock agreements in place. "The banks financed [our] El Dorado plant in Las Vegas on projections of input costs and product sales," says Perkins. "The old PURPA [Public Utility Regulatory Policies Act of 1978] formula [amounted] to a regulatory arbitrage. Now people are investing in deregulated businesses."
UBS led the debt financing of 62 percent of the 480-MW El Dorado plant, scheduled to come on line by the end of 1999. Location is key to financing, some developers say.
"A lot of these plants will still be able to get project financing because of the location they have picked," says Champagne. "A lot of them have contracts from large industrial plants or anchor tenants that make the banks less concerned about the project," he explains, describing the tendency for merchant plants to take on limited power purchase agreements rather than purely selling into the grid. "We're not going to see many 90/10 [percent] debt-equity deals, but we are going to see a lot of them leveraged 60 percent, and a lot are being given investment grade [risk-analysis ratings]," Champagne adds.
Overseas Activity Mixed
The United Kingdom, which initiated deregulation in 1990, nominally has encouraged merchant power plants for most of the decade. But now, the political clout of the coal lobby has pressured the government to place a moratorium on gas-fired plants until April 2000, according to David Lewis, vice president of Enron Europe in London.
"We've obviously got a couple of major projects in the queue, stuck in the moratorium, but we haven't given up hope of getting one or two through because policy always has a couple of chinks in it," he says. "It will take another two or three months to see," he adds.
If the United Kingdom doesn't shape up as a welcome market for gas-fired merchant plants, "we'll have to take our activity elsewhere in Europe," Lewis says. Emerging electricity trading markets in the Netherlands, Germany and Poland make those countries interesting, he notes. In emerging markets, demand for merchant plants is strong, although the risks are higher. In Brazil, the mid-term future seems bright for merchant plants, once recently privatized utility plants reach optimal output.
"Latin America will have a fairly robust demand," says Champagne.
But in some emerging market countries, like Pakistan, government interference in already-signed contracts has dampened future proposals. Allegations of bribery there landed some of the staff of one merchant plant project in jail, one developer says.
In other emerging markets, especially where gas and hydroelectric potential are great, merchant plants may not thrive.
"In Argentina, both hydroelectric [power] and natural gas are extremely cheap, which is causing prices to slump to between $20 to $18 per kilowatt-hour," says David Hurd of Merrill Lynch & Co. in Sao Paulo, Brazil. "Argentina has got too much capacity now - double what it needs - which is why it's trying to export electricity to Brazil."
Charles W. Thurston is a freelance writer who lives in Willow, N.Y.
California Certification: Still a two-step process?
In a precedent-setting case, the California Energy Commission ruled 3-2 in an August decision that U.S. Generating Co.'s La Paloma Generating Project, as a gas-fired plant that will sell into the California Power Exchange, was exempt from filing the required Notice of Intent with the Commission. The Energy Commission decided sales through the PX qualified the plant as having its output sold through a negotiated process. As the Public Resources Code is written, the exemption applies to gas-fired power plants that are "the result of a competitive solicitation or negotiation for new generation resources." Calling the PX - with its hourly bids for energy sales - the "very quintessence of competitive solicitation," the Commission granted La Paloma the exemption. Docket No. 98-SIT-1, Aug. 12, 1998 (Cal. Energy Comm'n).
But is the matter settled?
The Commission appears to have second thoughts. It has stated that its Energy Facility Siting Committee should "immediately move to examine the propriety and necessity of modifications to the NOI exemption process and offer recommendations to the Commission as appropriate." Further, the Commission emphasizes that its decision does not establish a presumption that all merchant plants are automatically exempt. Instead, each request should be reviewed on a case-by-case basis.
Dissenting Commissioner Michael Moore saw value in the NOI process and suggested it should remain: "Neither the Legislature nor the Commission has yet determined that the NOI process is unnecessary; yet, for all intents and purposes, that will be the result of this decision for natural gas-fired power plants."
Moore is particularly concerned that, with the exemption, decision-makers lose the opportunity to compare project sites with alternative sites. The NOI requires that alternative sites be selected. Moore also claims that many of the applications from projects that have received exemptions "face uncertainties" because they are trying to perform two steps at once. - C.J.L.
1 The Massachusetts procedure is described in detail in the recent decision by a hearing officer of the state's Energy Facilities Siting Board approving construction of a 350-MW, gas-fired, combined-cycle cogeneration plant proposed by Cabot Power Corp.
The board requires proof of five elements: (1) need for additional energy; (2) project superiority over alternative approaches, in terms of cost, environmental impact and reliability; (3) site superiority over alternative sites, on the same basis as test no. 2, above; (4) viability; and (5) minimization of environmental impacts to achieve an "appropriate" balance among environmental impacts, costs and reliability of supply. See Cabot Power Corp., EFSB 91-101A, Hearing Office Decision, Oct. 9, 1998 (Mass. Energy Facilities Siting Bd.).
However, as to need for power, it is not sufficient for the applicant simply to show that additional energy resources are needed for purposes of reliability. Instead, the energy must be necessary for consumption. See City of New Bedford v. Energy Facilities Siting Council, 413 Mass. 482 (1992).
In the Cabot Power case, the Siting Board explained how it interprets the state law test requiring a need for energy for actual consumption: "[C]onsideration of regional need must be a central part of any need analysis for a power generation project not linked to individual utilities by power purchase agreements." It notes that the state legislature clearly foresaw a need for "cooperation and joint participation in developing and implementing a regional bulk power supply of electricity."
2 According to the EPSA and other sources, these states include: Arizona, California, Colorado, Connecticut, Florida, Georgia, Indiana, Illinois, Massachusetts, Maine, Michigan, Missouri, Mississippi, Montana, North Carolina, New Hampshire, New Jersey, New Mexico, Nevada, New York, Ohio, Oregon, Pennsylvania, Rhode Island, Tennessee, Texas, Virginia, Washington, Wisconsin, West Virginia and Wyoming.
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