By KATE THOMAS
Nov. 20, 2000à‚–It’s a long shot, but coal could be the US energy market’s comeback kid.
High natural gas prices have fueled interest in new coal-fired electric generation just at a time when a spot market in coal is beginning to take shape.
Interest in coal is higher than it has been in years. A session on the outlook for coal-fired generation drew an overflow audience during Power-Gen International in Orlando last week.
“A year ago nobody was talking about building new plants,” says Chris Kasale, vice-president energy, coal, and emissions, for Dynegy Inc. “The whole idea of greenfield plants has only been talked about in the last couple of months.”
It’s been tough going for coal. The electric generating industry is struggling to cope with stringent rules governing nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions and now faces the possibility of new rules governing carbon dioxide (CO2) and mercury emissions, which are all the more challenging for coal-fired generators.
Natural gas will fuel 90% of the proposed new generating capacity, even though coal is presently the primary fuel for US electric generation and the US has by some estimates enough coal reserves to last 250 years. A proposed New York Mercantile Exchange (NYMEX) coal futures contract has yet to get off the ground.
Despite the uncertainty hanging over the coal market, an over-the-counter market has sprung up as producers and utilities attempt to manage fuel cost risks. And there is talk of building new coal-fired plants.
Some analysts estimate up to 30% of the 1 billion tons/year of coal produced in the US is traded in the spot market under 1 year or less contracts. Participation by companies such as Enron Corp., Dynegy Inc., and Aquila Energy (the trading arm of UtiliCorp United Inc.) has made development of an over-the-counter market all but inevitable, say industry analysts.
“For national producers and buyers, it is a significant change in the way we have done business,” says Henry Besten, vice-president, strategic marketing, for Arch Coal Co., a founding member of the Coal Trading Association.
Some companies have resisted the change, but Besten says this new way of doing business is a fact of life whether one likes it or not.
In the coal business, most contracts have been tailored to the needs of specific buyers. As a result, lack of a standardized product limited the ability of buyers and sellers to compare contract terms. Among the reasons for forming the new coal trade group, now about a year old, is to reach agreement among buyers, sellers, utilities, and trading companies on the terms of a master sales contract.
Standard terms will boost liquidity, Besten says. He says an agreement on a contract is about 30 days away.
The market is still in the transition stage, as long-term coal contracts expire, but it is growing, says Kasale. Coal is generally quoted on a quarterly basis going forward and as a 12-month strip.
Up to now, the market has used the so-called “NYMEX look-alike” contract as a reference product to trade against, says Thad Huetteman, a consultant and president of Power & Energy Analytic Resources Inc., in Atlanta, which markets an analytic tool for mark-to-market accounting in coal-power market positions.
NYMEX developed the coal contract expecting it to be traded in conjunction with electricity futures contracts. Because of the “perceived failure” of the electricity contracts, he says, NYMEX has been reluctant to introduce the coal contract out of fear it will get a similar unenthusiastic reception.
Huetteman says the work done to develop the NYMEX contract led to a “huge change” in over-the-counter trading, boosting liquidity and volume in an otherwise fragmented market.
Presently, about six brokers are actively making a market in coal, Besten says.
Merchant energy producer Dynegy trades around the coal-fired plants operated by its Illinova subsidiary, says Kasale. Dynegy determined that to be a true convergence player, the company would have to become active in the coal as well as the natural gas market.
Three coal products are being actively traded, two in the West and one in the East. The NYMEX look-alike contract traded in the East is a 1% sulfur 12,000 btu Appalachian coal barge product with a trading area on the Ohio River near at Big Sandy.
The other two are Powder River Basin coal products transported by rail. One is 8,800 btu and the other is 8,400 btu. Some puts and calls, straddles, and swaps also are being traded, Besten says.
But Huetteman says the market is not likely to live up to its potential until pending environmental rules governing NOx, sulfur dioxide (SO2), and possibly carbon dioxide (CO2) emissions are clear and lawsuits affecting US coal-fired plants are settled.
“I think people are waiting, in part, to see how the EPA (US Environmental Protection Agency) regulations will affect coal across a broad part of the country,” Huetteman says. “They are waiting to see what will happen when the last shoe is dropped.”
Once the regulatory picture clears, Huetteman foresees higher volatility for coal prices, making financial instruments more useful as a hedging tool, and therefore, more valuable. At present, coal prices vary only about 8%-12%, making coal far less volatile than natural gas and electricity.
“I think people are waiting to trade a clean spark spread,” he says. Coal trading is not the only aspect of the industry that will turn on the outcome of air quality questions.
As gas prices have risen to $4-$5/Mcf, the economics of building coal-fired electric generating plants have improved and a handful of companies have begun talking about building units.
“Electricity demand is outpacing projections,” says Ron Whiting, president of Peabody International, speaking at Power-Gen in Orlando. “A Palm Pilot draws as much electricity as a refrigerator. We will need new base load generation.”
The cost of building a coal-fired plant has come down to about $1,200/kw, compared to about $560/kw to build a combined cycle gas-fired plant, says Bob McIlvaine, president of McIlvaine Co., an environmental and engineering consulting firm. But he says the differential reverses when operating costs are taken into account.
At $4/Mcf for gas, coal becomes attractive as an alternative since the cost of gas represents about 85% of the cost of operating a gas-fired plant, compared to 50% of a coal-fired plant, he says. Presently, McIlvaine says, the cost of operating a coal-fired plant is about $1.23/MMbtu vs. about $4.50/MMbtu for a gas-fired one.
High gas prices helped revive a large-scale coal demonstration project in Illinois. “I actually thought it was dead,” said Bob Kripowicz, acting assistant secretary, US Department of Energy (DOE), at Power-Gen.
In conjunction with DOE, Bloomington, Ill.-based Corn Belt Energy Corp., a transmission and distribution cooperative, is planning to build a $137 million, 91 Mw mine mouth plant in Logan County, the first new coal plant in the state in 14 years. The unit will serve as the co-op’s first base load power plant.
The plant will be the first large scale demonstration of a boiler design to cut (NO2) emissions substantially, say Corn Belt executives. The plant will also have scrubbers installed for SO2. Because it has DOE backing and because Illinois is a major coal-producing state, Corn Belt don’t expect much opposition to the plant, if any, says Dave Hawkinson, marketing director.
Plans call for construction to begin in 2001 and completion by late 2004. But Steve Trenholm of Harza Engineering Co., Corn Belt’s consultant on the project, suggests the timetable may be have to be modified since the project was just announced in October. Completing the permitting process, he acknowledges, will be a major hurdle.
In October, a top executive at City Public Service Co.(CPS) of San Antonio, the second largest municipally owned electric utility in the US, said he favored building a coal-fired plant. The biggest concerns are permitting a new coal plant and community acceptance, Milton Lee Sr., vice-president of electric transmission and distribution for CPS, said at a conference in Austin.
Meanwhile, PG&E Corp. has put on hold a $400 million proposal to replace two existing coal-fired boilers at the Salem Harbor power station in Salem, Mass. The California-based concern has said it will replace the units with a single state-of-the-art coal-fired boiler equipped with modern pollution control equipment that will cut NOx emissions by 55%, SO2 by more than 65%, and particulates by more than 25%.
Before proceeding, Lisa Franklin, a PG&E spokeswoman says, the company will wait for the Massachusetts Department of Environmental Protection to issue air emissions rules. The proposed rules “would put pressure on [construction] of any coal plants at all,” she said. The company had hoped to begin construction in 2002 and complete the upgrade by 2004.
Wisconsin Energy Corp. earlier this year said it envisions building at least two 600 Mw coal-fired units during the next 10 years as part of a major expansion program to keep up with rising demand. Spokesman Chris Iglar says the company plans to make an initial filing in November with Wisconsin state regulators describing the proposal, including such things as preferred sites.
“We expect a fair amount of opposition from environmentalists,” he says, more particularly because the plants will burn coal. He says the company is prepared for a long process.
Coal is one reason the nation has affordable power today, says Curtis Davis, senior vice-president, power generation, Duke Power, a unit of Duke Energy Corp. Prices have remained stable and US resources are abundant. Speaking at Power-Gen, Davis called for a balanced portfolio of fuels that includes coal, but said natural gas is “where the market is driving us. If we want to maintain reliability, coal has to be a player as well.”
But, he said, coal-fired generation is a “very emotional issue” with the public. As for the possibility of building coal plants, the number of unanswered questions make “the risk profile for anything other than gas very high,” Davis said.