The high cost of coal plants has generally limited their development to utilities with large rate-base markets. Will rising natural gas prices spark coal plant development by non-rate-base energy providers?
by: Steve Blankinship, Associate Editor
Sustained higher natural gas prices are forcing many utilities and some non-utilities to look at new coal plant development. Modern coal technologies – including circulating fluidized combustion (CFB), greatly improved emission control systems, supercritical boilers, and integrated gasification combined cycle (IGCC) – allow coal to be used with dramatically lower emissions than was possible when the last round of coal plants were built. The catch, of course, is that coal plants are more expensive to build than combined-cycle gas plants, meaning that independent power producers (IPPs), the segment that built virtually all new capacity over the past decade, are far less likely to develop coal plants.
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That would seem to leave the job of developing new coal-fired capacity back upon the broad shoulders of the companies that have always built them – regulated utilities that serve rate-base markets composed of defined customer bases. The regulated sector bows to intense regulatory scrutiny and settles for a restricted yet steady rate of return over three or more decades.
But the trend toward deregulation in the United States – tentative and inconsistent though it may be – has nonetheless altered the U.S. power market dynamic forever. Few utilities believe there will ever be a total retrenchment to the days of closed transmission access and power purchases made only between mutually consenting regulated utilities. Meanwhile, the independent power provider segment, despite the beating it has taken in recent years, will almost surely remain a major force in the U.S. power supply. That begs the question: Will some new coal projects be developed outside, or at least partially outside, the rate-base umbrella?
“It’s now fashionable to say no one will build new power plants without either rate-base treatment or long-term contracts,” John Rowe, chairman, president and CEO of Exelon Corp. told a power industry gathering earlier this year. “I do not believe that is true. I believe there are circumstances in which my company would build merchant plants, and I believe we would be likely to do that before we would submit to some kinds of regulation.”
Such a statement from the man who heads one of the nation’s largest electric utilities underscores how much the landscape has changed. Many traditional vertically integrated electrically utilities already operate some or all of their plants outside a customer rate-base, allowing them the flexibility to maintain service to their native customer load and still capitalize on wholesale transactions beyond their customer base. Some coal projects that will operate exclusively outside the rate-base are already well into the development phase. Others are already operating.
The State of Illinois has issued the air permit for the $2 billion-plus Prairie State Energy Campus, Peabody Energy’s mine-mouth coal project in Washington County, Illinois consisting of two 750 MW coal-fired units. A group of Midwest rural electric cooperatives and municipal agencies have entered into a definitive agreement to acquire 47 percent ownership of the Prairie State Energy Campus and an equal amount of the plant’s output. Peabody is also developing an identical 1,500 MW Thoroughbred Energy Campus in Kentucky that would sell power to utilities, co-ops and municipals through long-term contracts. Also in development is Peabody’s Mustang Energy Campus, a 300 MW plant planned near Grants, N.M. that will demonstrate state-of-the-art clean coal technology using an advanced sodium scrubbing system. Mustang has received a U.S. Department of Energy Clean Coal Power Initiative grant.
Chicago-based Midwest Generation, an unregulated subsidiary of Edison Mission Energy, recently restarted two coal-fired units in Will County, Illinois, with a combined capacity totaling 310 MW. Other coal plants originally built as rate-base facilities but now operated largely in the merchant arena include coal plants owned by Atlanta-based Mirant and Houston-based Texas Genco. Mirant has close to 5,000 MW of coal-based generation at four plants in the Mid-Atlantic Region, all of which serve merchant markets. TexasGenco owns more than 4,000 MW of coal-fired generation at its Parish and Limestone plants serving the Texas wholesale market.
And Reliant Energy’s Seward plant near Johnstown, Pennsylvania began commercial operation last summer, providing power exclusively to the merchant spot market through the PJM Interconnection. The 521 MW circulating fluidized bed (CFB) plant is the largest waste coal-fueled plant in the world. It’s a high-profile operation in other terms as well. “Seward Station enjoyed its best month of operation to date in May with availability and capacity factors of 99 and 92 percent respectively,” said Dave Freysinger, senior vice president of generation operations at Reliant Energy. He notes that Seward has received the state’s Governor’s Award for Environmental Excellence.
Tapping the IPP Brain Trust
The U.S. Department of Energy (DOE) identifies about 100 new coal-fired projects, representing 65 GW of generation, in various stages of development in the United States. In light of how drastically U.S. electricity markets have changed over the past 15 years, it seems almost certain that some of the projects eventually built will be outside of the traditional regulated utility rate-base umbrella.
“We definitely believe that independent power producers have a place in coal-fired generation development,” says Dave Fiorelli, president of the business development group for Omaha-based Tenaska, Inc. Tenaska has developed 9,000 MW of generating capacity and currently owns and manages 7,600 MW in operation or under construction. The company has raised more than $7.3 billion in aggregate financing.
Fiorelli says highly qualified IPP staffs oversaw the development, engineering, design and construction of the vast majority of gas-fired power projects placed into commercial operation in the United States over the last decade. He believes some of them are now ready to turn their skills to coal-fired development.
“IPPs bring creativity and innovative thinking to the development process,” he says. “I believe these attributes will allow IPPs to assist municipal utilities, cooperatives and even investor-owned utilities in solving some of the issues associated with bringing a large, complex and costly coal project to fruition.”
For example, Fiorelli explains how a co-op or municipal utility might want to build a coal project, even though its current need may not be enough to build a project big enough to take advantage of economies of scale inherent in such plants. “They may not have the staff needed to manage such a large and complex project. So an IPP might agree to develop, construct and operate a large coal-fired station for the co-op or municipal utility and take some of the plant’s output for some period of years. That would allow the utility to grow into a larger project as its power needs increase.”
Fiorelli even sees a place for IPPs to participate with investor-owned utilities. “In areas that still are regulated, utility commissions have become increasingly concerned with the cost of new generation,” he says. “By contracting with an IPP for a turnkey coal-fired project, an investor-owned utility can leverage the experience of an IPP’s staff and shift the risk of construction cost overruns to the IPP. In addition, long-term contracts with IPPs for coal-fired generation can help utilities avoid the rate shock experienced by customers when large, capital-intensive projects are placed into rate base.”
So far as going it on their own, playing the coal game is expensive, and few if any IPPs will be willing or able to ante up, says Jeff Schroeter, president of Dallas-based Genovation Group. Schroeter has developed more than 8,000 MW of gas-fired combined-cycle capacity, 100 MW of peaking capacity, 500 MW of lignite-fired CFB and 6 MW of wind generation.
Citing factors that are changing the opportunities for small developers, he recounts how in the qualifying facilities days, small developers were innovating, entrepreneur types. “In the early QF days, they had tremendous uphill battles with the investor-owned utilities for avoided cost power purchase agreements. Then with the EPAct of 1992, it became much easier to sell power with market driven pricing. But now with retail deregulation in retreat or stasis, the big utilities are again more in control of new generation decisions.”
Furthermore, says Schroeter, gas projects take two to three years and anywhere from $2 million to $6 million to develop, while coal takes three to six years and $7 million to $20 to develop. “The cost and time duration of development is a huge barrier to entry for the small developer.” Since coal projects are so capital intensive, Schroeter believes they are far more likely to be developed by utilities with captive ratepayers because merchant risk for power sales is just too large. He adds, however, that IPPs may act as jump starters or consultant advisors.
Coal By Wire
If significant amounts of new coal capacity are to be built – be they inside or outside the rate-base – there must be a way to get low-cost coal-produced power to customers who need it most. Transmission infrastructure inadequacies, therefore, remain a huge issue. And additional rail infrastructure needed to move more coal to more sites is at least of equal concern.
“It certainly makes more economic sense to construct additional transmission capacity for coal fueled, baseload generating capacity than for intermediate or peaking capacity in order to spread the cost over as many kilowatt hours as possible,” says Natalie Rolph, Black & Veatch chief economist for enterprise management solutions. “It also makes sense because it is harder to site coal generation near major population centers than it is to site gas-fueled generation near cities. Moreover, the major low-cost, low-sulfur western coal producing regions are very distant from major population centers.”
She says that unless a way to permit and finance new transmission is found, states like California – and most major cities for that matter – will be dependent on high-cost gas-fired generation for a large part of their future electric energy requirements. “We are still struggling in this country with the issue of how to pay for transmission improvements or how to induce transmission investment,” she laments. “Complicating the situation is the fact that in more than a few locations, existing owners of coal-fired generation oppose added transmission to facilitate competition.”
Colin Kelly, vice president of generation development at Peabody, says baseload capacity will be needed in all regions of the United States by the end of this decade, and any large-scale baseload project will require substantial transmission upgrades ranging between 5 and 10 percent of project costs. “Expanding the transmission network for baseload facilities that run 24 hours a day, seven days a week at very high capacity and transact over long-term periods makes good sense,” he says. “The cost can be justified by generators and load-serving entities alike.”
Kelly thinks that the RTO obligation to conduct regional transmission planning should help in time. He also believes the long lead times associated with permitting and constructing coal fueled facilities will allow concerns with transmission to further evolve and find resolution. “Almost everyone agrees we need more transmission, and many also are realizing it is far more cost-effective to move coal by wire than by rail.”
Long Term Contracts/Partners Needed
Clearly, the single biggest issue for the merchant sector is financing. “Unless the merchant share of a project is to be very small, merchant coal plants are not even in consideration by the financial community for IPPs,” says Rolph. “Lenders want to see guaranteed revenue streams in the form of long-term power purchase agreements (PPAs) or off-takes for a large portion of a new plant’s output. For IPPs, that’s a ‘chicken-and-the-egg’ problem because the developer must guarantee a price for the coal-fueled energy in order to get PPAs but can’t secure financing or obtain the interest of EPC contractors to firm up costs – due to the high cost of such proposals – without showing he has committed customers and a deal that can be financed.”
Furthermore, says Rolph, in states without retail access, investor-owned utilities have incentives to build their own coal capacity because ownership is the key to rate-base maintenance and continued stockholder returns. She says there was a time when PPAs might have relieved IOUs of debt obligations. “However,” she says, “the financial community now views long-term capacity payments much the same as it views debt.”
She notes that since over-building of merchant capacity occurred largely in states with retail access, it is yet to be determined if IPPs can overcome the financing hurdles and develop coal-fueled generation for electric service providers. “Their best chances to succeed should occur in states like Texas and markets like PJM that clearly need additional generating capacity.”
With the large amount of capital required for a coal plant – $1400/kW versus $600/kW for a combined-cycle project – the asset must access long-lived debt to keep its annual fixed charges in an acceptable range, says Schroeter. “Most coal plants have 25 to 30 years of debt. It would be very difficult for debt holders to accept only a three-year power purchase agreement without additional contingent equity support from the project sponsor. That is effectively what rate-based projects are – they have captive ratepayers and if costs become excessive, rates can be raised but only to a politically acceptable level.”
The size and complexity of a project like Prairie State requires partners, says Kelly. “While Peabody will maintain a long-term interest in Prairie State, the facility is being developed by the Prairie State Generating Co., comprised of Peabody and the Prairie State Interest Group, made up of the six electricity suppliers owning a combined 47 percent interest, and a future operating partner. Most of the remaining portion will be shared between Peabody and the future operating partner.”
Kelly says municipal and cooperative agencies will be encouraged to band together in projects to get the economies of scale, which can save 10 to 25 percent on the capital cost. And in states that go to full deregulation, he believes some large price-sensitive customers will move toward long-term participation in new coal plants to hedge the volatility in the power market driven by volatile gas generation, which is on the margin. “You also may expect some of the industrials to work with municipal and cooperative agencies that have low cost of capital to procure power from these very capital-intensive projects at a discount to the market, due to the low capital cost of their providers.”
Is Public Perception Changing?
Certainly, the length of time to achieve permitting for any project is critical, and a significant factor tied to the longer permitting time required for coal plants relates to public acceptance, or, more likely, lack of it.
“The public still thinks electricity comes from a socket,” says Schroeter. “They don’t have a clue where it comes from except when the price goes up, like it is now with $6/MMBtu gas, and they can just maybe associate it with the price of natural gas. The other time they are aware of it is when an environmental story appears about air pollution say in a local metro area. Somehow, the public never thinks about autos as pollution sources, but big central station coal plants must be big polluters because they have tall stacks.”
And although Rolph doesn’t see much change in public attitudes toward coal, she believes some coal plant developers have been successful in education efforts to obtain local support. Peabody is a good example. Kelly says his company’s proposed projects enjoy extraordinary support from area residents, community leaders and elected officials of all political stripes in regions where their projects are being planned. “Proactive, candid communication facilitates better understanding of project fundamentals,” he says. “Third party surveys show that project approval increases as residents learn more about creating low-cost electricity, hundreds of local jobs and millions in annual economic benefits.”
Diverse Partnerships May Emerge
Consortiums may be the solution to IPP developed coal plants, says Rolph. Recent conversations and information exchanges hosted by Black & Veatch with the financing community would indicate financing is available for certain coal plants, specifically, for projects based on PPAs for the majority of their capacity, and projects developed with sound contracts and with credible engineering and construction firms.
“According to some reports, the few coal plants with excess capacity in areas that can leverage retail markets are making a killing,” she says. “This has caught the interest of the financing community. The IPPs that can afford and will accept the risk and cost to solve the ‘chicken and the egg’ dilemma should be able to finance coal plants. This may require consortium, or partnering type agreements between IPPs, OEMs and qualified EPC contractors. Most OEMs and EPC contractors will not enter such endeavors on an at-risk basis.” p
For a more in-depth look at the various issues impacting the coal-fired generation sector – including new coal projects, environmental regulations, emission control, and coal supply and handling – plan to attend COAL-GEN 2005, Revival of the Fittest, August 17-19 in San Antonio (www.coal-gen.com).