Coal: Still King
The era of inexpensive electricity is probably over. “Four cents a kilowatt-hour is a reality,” said Raj Rao, president of Indiana Municipal Power Agency. “It won’t go back to 2.5 cents.”
The driver is the rising cost of fuels. Historically, fuel price trends start with oil, said Rao. Then natural gas. Then coal.
Coal, which is used to generate more than half of America’s electricity, has been the nation’s abundant and low-cost fuel. It’s still pretty abundant. But it’s no longer low-cost.
A combination of circumstances has ratcheted up the price of coal over the last couple of years. Among them: soaring demand and transportation bottlenecks.
During the economic slump at the turn of this century, coal demand fell and coal production company bankruptcies rose, especially in Appalachia, where minable reserves had been declining for a decade. As the economy recovered, demand rose sharply—both in the United States and around the globe, especially in China. U.S. coal producers, particularly in the eastern part of the country, were hard-pressed to satisfy growing requirements for the fuel.
As a result of the tight market, public power utilities that rely on coal from Appalachia and the Midwest have seen a significant jump in their fuel costs. Santee Cooper Power’s costs for Kentucky coal have doubled, said Laura Varn, vice president of corporate communications at the South Carolina utility. Wally Haase, general manager of the Jamestown Board of Public Utilities in New York, said the town has seen close to a 100 percent increase. And Indiana Municipal Power Agency, which uses Midwestern coal, has also seen a significant jump in price.
Public power utilities west of the Mississippi tend to get their coal from the Powder River Basin. The market for coal from the basin, where extensive reserves can be mined cost effectively on the surface, has experienced little of the price volatility of eastern coals. “We’ve seen an increase of a couple of dollars a ton,” said Bill Burks, chief operating officer of City Utilities of Springfield, Mo. That includes a premium that the city is paying for higher Btu coal, he said. By contrast, the price paid by the Jamestown Board of Public Utilities for Pennsylvania coal has leapt from $35 a ton to $65, said Haase.
Another factor pushing up coal prices is the cost of freight, which has risen sharply. One reason for higher freight charges is congestion on the railroads, according to the Department of Energy’s Energy Information Administration. The market tightened so quickly that rail companies did not have sufficient lead time to get crews and equipment where it was needed, said one utility expert.
During the economic downturn in 2001, the demand for rail freight fell. Railroads laid off staff and cut back on equipment, especially locomotives. As revenues declined, the nation’s largest rail systems grew unhappy with the payback for the hundreds of millions of dollars they had invested in upgrades during the 1990s, said EIA. A number of analysts believe the rail companies were under extreme stockholder pressure to get their rates up so they could earn the cost of capital.
But according to a Feb. 17 article in The Wall Street Journal, some electric utilities think there could be another reason for higher rates—possible coordinated pricing between the nation’s two largest railroads, which is driving up the cost of shipping coal from the Powder River Basin. The U.S. Department of Justice is investigating the pricing practices of Burlington Northern Santa Fe and Union Pacific, said the newspaper. It quoted a Justice Department spokeswoman, who said the agency’s antitrust division was “looking into the possibility of anticompetitive practices involving the transport of coal.”
Within the last year, the two railroads have reversed their policy of entering into long-term confidential contracts with utilities, claiming that it was leading to lower revenues, according to The Wall Street Journal. That move had a breath-taking impact on Springfield City Utilities. “On Jan. 1, Burlington Northern Santa Fe increased our shipping costs by 45 percent,” said Springfield’s Burks. What’s more, the railroad added a $2.25 fuel charge per ton shipped. “The upward pressure on the price of the product itself pales in comparison with coal transportation costs,” he said. “The delivery of coal accounts for 75 to 80 percent of the cost of the product.”
City Utilities of Springfield is a captive shipper, which puts it at a disadvantage, said Burks. Santee Cooper also is captive to one rail company, CSX. That’s why Santee Cooper’s longstanding relationship with CSX is so important, said Varn.
Wisconsin Public Power Inc. does not negotiate coal transportation contracts directly, said Peter Steitz, senior vice president of power supply. That’s the task of the operator of WPPI’s jointly owned coal plant. “But we’re captive, generically,” he said. WPPI buys power from other utilities in Wisconsin, and the higher coal and transportation costs are passed on in higher prices to WPPI in its power purchase agreements. One plant operator has tried to use the construction of a 15-mile rail spur as leverage to create competition.
Omaha Public Power District in Nebraska has worked to ensure it has competitive access to coal, said Dan Kloock, division manager of fuels. “We have origin and destination access for Union Pacific and Burlington Northern Santa Fe. That’s very critical.”
Jamestown Board of Public Utilities splits its coal deliveries between railroad and truck, Haase said. “We have only eight to 10 days of coal on site, so it’s important to have on-time deliveries,” he said. “When the railroad lets us down, we beef up truck transportation.”
Some public power utilities have another bargaining chip—their own coal mine. That has helped at least one utility negotiate lower transportation rates with its shipper. Arizona’s Salt River Project has not been hit too badly by significant rail transportation problems, said Randy Detrick, manager, wholesale markets. Its greatest exposure is at two coal-fired plants in Colorado, but a plant-owned coal mine is helping “to keep problems at bay” by providing half the coal needed for power generation, he said. But SRP is not just sitting on the sidelines, said Detrick. “We participate in industry groups that are trying to create a more level playing field between coal buyers and the railroads. Just because we’re not really being hurt doesn’t mean we’re not trying to make a difference.”
The winter of 2004-2005 was certainly one of discontent for coal deliveries. Shipments by rail—and barge—were disrupted by a number of problems, most of them weather-related. In addition to a couple of derailments, Burlington Northern Santa Fe and Union Pacific had problems with freezing coal from the Powder River Basin, said Springfield City Utilities’ Burks. That backed up the railroads, and left the city with “an uncomfortably low” stockpile of coal as it prepared for the peak summer season, he said.
On the Ohio River, where shipping costs were already on the rise, barge traffic slowed because of flooding. That put pressure on the coal inventories of the many power plants along the waterway, including Indiana Municipal Power Agency.
To offset higher fuel prices, some public power utilities are boosting the efficiency of existing coal-fired plants. OPPD, for instance, is looking for opportunities to decrease the heat rate, said Ken Roth, division manager of projects and construction.
But for Santee Cooper, whose fuel prices have skyrocketed, there is little option but to pass some of that cost on to customers. “This is one of the biggest customer issues we have ever faced,” said Varn. Three-quarters of Santee Cooper’s electricity is produced by coal. The utility’s industrial customers have seen a 17 to 20 percent increase in their bills, while residential customers have seen an 8 to 9 percent increase, said Varn.
It’s not just higher coal prices that are putting upward pressure on electricity generation costs. Hill & Associates, a consultant to the coal and electricity industries, expects the Clean Air Interstate Rule, issued by the Environmental Protection Agency in March, to boost power prices significantly. That rule, which will be phased in over 10 years, establishes limits for sulfur dioxide and nitrogen oxides from power plants in 28 eastern states and the District of Columbia. Hill & Associates estimates the cost of buying and operating emission control equipment to comply with the rule could lead to a 25 percent increase in the cost of electricity by 2010, with an additional increase of 10 percent in 2015.
A number of public power utilities have already retrofitted their coal-fired power plants to improve environmental controls, and others are planning to do so. SRP has funded “significant improvements” at the six coal-fired plants it owns in whole or in part, said Detrick. One such project was the addition of scrubbers—flue gas desulfurization systems—to the 2,250-MW Navajo plant. As one of the plant’s five owners, SRP contributed to the upgrade, which cost $420 million.
To reduce nitrogen oxide emissions, OPPD has retrofitted low-NOx burners. Santee Cooper is employing another technology for controlling NOx emissions. The South Carolina utility has installed selective catalytic reduction systems at two of its plants—the 1,200-MW Winyah plant and the 1,160-MW Cross plant. Emission control equipment at the Cross plant cost more than $185 million.
As the co-owner and operating manager of two older coal-fired units at the Fayette Power Project, the Lower Colorado River Authority in Texas has committed to reduce sulfur dioxide emissions by 90 percent and nitrogen oxide emissions by 50 percent by 2012. Since that 2002 commitment, LCRA already has made boiler modifications to the units that have reduced NOx emissions by roughly 70 percent, said LCRA spokeswoman Robbie Searcy. Like LCRA, CPS Energy (formerly City Punlic Service) in San Antonio has reduced its nitrogen oxide emissions. In addition, the utility will add baghouses—which will take the place of less efficient electrostatic precipitators to remove particulates—and scrubbers to remove SO2 at the two-unit 860-MW Deely plant within the next 10 years, said Jim Nesrsta, director, generation planning and nuclear. A planned upgrade of the scrubbers at the J.K. Spruce plant will remove sulfur dioxide “in the high 90s,” he said. Nesrsta put the cost of all the upgrades at $300 million.
Retrofitting coal-fired plants provides cleaner power. But it does not necessarily provide more power. And as public power utilities peer into the future, they see customer demand growing. DOE’s Energy Information Administration said in March that it expects electricity demand to increase by 3.4 percent this year and an additional 2.1 percent in 2006.
“Somewhere in the 2008-2009 time frame, we will need new capacity,” said City Utilities of Springfield’s Burks. It’s a conclusion that a number of other public utilities have reached. And increasingly, that new capacity will be coal-fired.
Despite the run-up in the cost of buying and transporting coal, the fuel is still less expensive than natural gas. “A pulverized coal plant with all the environmental bells and whistles is right in there—cost per kilowatt-wise—with coal gasification and not far off the next generation of nuclear plants,” said an expert at an investor-owned utility. And with those emission control technologies, a pulverized coal plant can operate as cleanly as the most advanced coal technology—the integrated gasification combined-cycle.
That’s why CPS Energy chose coal to power its new 750-MW plant, said Nesrsta. “We believe that pulverized coal can be clean.” It’s a belief shared by many in San Antonio, thanks to the utility’s outreach efforts. To provide feedback and recommendations, CPS Energy created a community advisory group a couple of years ago, and let it run. “We invited one of the most outspoken environmental activist to participate in the group,” said Nesrsta. “We have convinced many local activists that building the new plant is a prudent thing to do.”
Community outreach is critical when new coal-fired power plants are planned. Despite their state-of-the-art environmental controls, today’s new coal plants are still dogged by a reputation as “dirty.” Peabody Energy, which is building a 1,580-MW advanced technology coal plant—the Prairie State Energy Campus—in southern Illinois, began a community outreach program in 2002, even though construction is not slated to start until 2006.
Indiana Municipal Power Agency is among the owners of the Prairie State Energy Campus. “We took a leadership role in bringing people together for this project,” said IMPA President Rao. Other owners include the Kentucky Municipal Power Agency, the Missouri Joint Municipal Electric Utility Commission and the Northern Illinois Municipal Power Agency. Paducah Power System of Kentucky, Wolverine Power Supply Cooperative, Inc. and Soyland Cooperatove, Inc. have agreed to purchase a significant share of the plant’s output.
The Prairie State Energy Campus will employ what’s known as supercritical technology, which creates steam at higher temperatures and pressures than traditional coal-fired plants, thereby increasing efficiency and significantly reducing emissions. “Being a participant in the plant will provide our members with a low-cost and environmentally friendly supply of electricity for the coming decades,” said Rao.
Like other public power utilities, Santee Cooper needs new capacity for continued growth, said Varn. “We looked at various fuels for a new plant, and even with rising prices, coal was still the most available fuel,” she said. The utility plans to more than double the size of its Cross power plant, adding two 600-MW pulverized coal units with the latest emission control technologies. “We’re not a large utility, but we want to be big in terms of environmental performance.”
When OPPD looked at various technologies to meet its projected load growth, “pulverized coal came right to the top,” said Roth. OPPD needed only about 300 MW of new capacity, but wanted to take advantage of the economies of scale that a larger plant would offer. “So we went to other public power entities—in and out of state—and got seven to participate,” he said. The planned 663-MW plant will have the best available technologies—scrubbers, baghouses, selective catalytic reduction systems, low NOx burners. “Its regulated emission rates will be as low as any plant in the country,” said Roth.
Sometimes, a public utility can’t go big. That was the dilemma faced by the Jamestown Board of Public Utilities. Its old coal-fired plant was too small to warrant the investment in baghouses and scrubbers, said the board’s Haase. “We looked at 12 different ways of meeting customer needs, including closing the plant and buying power off the grid,” he said. “We concluded that we could best serve our customers’ long-term interests by staying in the generating business and using the fluidized bed technology.” Haase said the city’s studies showed this technology—which significantly reduces emissions, even when burning higher-sulfur coal—would be the lowest cost option over a long period of time.
The size of the planned facility: just 40 MW.
Jamestown BPU’s total installed capacity is only about 100 MW. “But even though we’re a little guy, we can’t be dependent on just one fuel source,” said Haase. “Diversity is key.”
That message is echoed by numerous other public power utilities across the country. Santee Cooper, for instance, relies on natural gas, hydro and nuclear energy to provide about 25 percent of its power, said Varn. “We want to maintain a diversified portfolio.” Likewise, CPS Energy in San Antonio meets customers’ needs with a combination of natural gas, wind and—of course, coal. “We have 160 MW of wind energy,” said Nesrsta. “And we’re in the process of adding another 100 MW.”
Ultimately, public power utilities will do what it takes to ensure their customers have enough reliable—and clean—power.
“Whatever we do, at the end of the day, we are responsible for making sure the lights come on,” said Springfield City Utilities’ Burks.
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