With Deregulation, More Power Transmitted over Greater Distances in U.S.
The Blade, Toledo, Ohio (September 7, 2003)
Sep. 7--About 15 years ago, your local electric utility fired up its power plants and filled its high-voltage transmission lines with hundreds of megawatts of electricity to send power to your home.
Today, those lines have a second purpose: interstate commerce.
Sale of power between utilities and power brokers jumped to 2 million transactions in 1999 from just 25,000 in 1995. Such sales place huge amounts of power on lines that often carry the electricity across hundreds of miles. Ohio has 12,000 miles of high-voltage transmission lines, supported by big steel towers that dot the landscape.
"We've got a network out there that works very well, but it was never intended for the transmission system of Ohio to take power generated in the Great Plains and ship that power to the Northeast," said Paul Kure, a staff engineer with the East Central Area Reliability Council. The council is a Cleveland industry group established to ensure adequate electricity in a nine-state region that includes Michigan and Ohio.
That kind of use for transmission lines has come about since 1993, with the deregulation of the electric industry and opening of the power grid to non-utility power producers. But utilities and power brokers are reluctant to divulge how much power they buy and sell and at what prices, so the extent of such commerce is uncertain, Mr. Kure said.
On an average day, the lines carry up to 2,000 extra megawatts of power from dozens of power-swapping deals that were transacted a day, a month, or even a year earlier. One megawatt is enough to power about 1,000 households, or about the size of the Toledo suburb of Whitehouse; 2,000 megawatts could power a metro area the size of Dallas-Fort Worth.
Such power sharing is big money. Some transactions can be for as little as $7,600, but one day last week there was a group of purchases totaling $1.85 million for 66,400 megawatts that were to pass through Ohio's transmission grid.
FirstEnergy Corp., the Akron-based parent of Toledo Edison, is a frequent power buyer.
The company said it can generate 13,300 megawatts with its own plants, but on any given day is buying between 3,000 and 6,000 additional megawatts to offset demand.
The utility has said the hot weather escalated demand on Aug. 14, the day of the nation's biggest blackout. It would not say how much power it was trying to buy that day, but in 1998, when it had a smaller service territory, its peak demand was about 12,500 megawatts.
FirstEnergy can generate about 13,300 megawatts if all of its power plants are working, but its customers usually demand far more, sometimes as much as an additional 10,000 megawatts.
Utilities often arrange long-term contracts for power negotiated on a yearly or monthly basis. But if a shortfall is imminent, the utility goes to a spot market a day or so in advance to buy power.
The purchased power may be generated several hundred miles away and that amount is delivered, although what is delivered isn't the actual electricity generated.
Instead, a Michigan utility, for example, will boost power by the ordered amount, say 400 megawatts, for a buyer in, say, New York. The transmission lines of each utility in between will experience a slight boost in power coming in and flowing out, creating a ripple effect until power levels rise to the contracted-for amount at the New York utility needing the 400 megawatts.
Thus, the transmission system stays balanced, which is important. Otherwise, transmission lines and power plants can become overloaded and will shut down automatically, as happened with the big blackout last month.
FirstEnergy has 103 points that link to 14 other electric systems. In Ohio, it relies mainly on about 7,000 miles of medium-sized transmission lines, which can carry about 1,000 megawatts, and smaller transmission lines that can handle about 80 to 100 megawatts and are used for transmission as well as distribution to substations.
These are different from the smaller power lines strung from poles in a neighborhood; their purpose is to deliver electricity to homes and businesses, not transport it long distances.
A transfer of power usually occurs within seconds and is monitored by each utility, which is compensated for transmitting it. The pay, however, may be in cash or be credit for future power purchases.
Utilities along the expected path of the ripple usually are warned that a boost in power is coming at a specific time. The utilities can curtail the influx if it the extra flow would be a problem.
A utility typically could have more than 150 transactions a day pass through its transmission system, either from its own purchases and sales or from power flowing through its system for someone else, said Mike Wilczek, senior markets editor for Megawatt Daily, a McGraw-Hill publication that tracks power prices.
The buying and selling of power and the wheeling of it across the grid system is a fairly complex process, with computers controlling much of the transactions and opening and closing electrical switches to allow electricity to pass through, Mr. Kure said.
Computers also reroute power or disconnect grids to prevent overloads and burnouts as occurred on Aug. 14. That day, a cascading blackout reached from the Midwest to the Northeast and included part of Canada.
"Contractually, you can even have a transaction going north to south and one south to north over the same wires," Mr. Kure explained. "The flows will generally cancel each other out.
"Sometimes you'll have flows already going in one direction and have someone attempt to send power in the other direction. If more power is flowing in one direction and power is added to the grid, you can have it suddenly going in a different direction."
Just before the Aug. 14 blackout, several utilities noted that power flowing around Lake Erie suddenly reversed direction as power plants tripped offline.
Although power transactions usually are planned at least a day in advance, grid operators are usually making adjustments hour by hour, minute by minute, Mr. Wilczek said.
A utility increases or decreases output of power based on demand and power to be transmitted. It can boost output at its plants or reduce it, and can add to its outside power purchases or reduce them.
On short notice, however, the price for power can be steep.
During an unusually hot stretch in late June, 1999, power shortages drove the cost of a megawatt-hour up to $7,500 on the spot market.
Costs were more reasonable this summer, according to the Intercontinental Exchange, an Internet-based forum in Atlanta where hundreds of utilities, independent power producers, and other power brokers buy and sell electricity daily.
A megawatt-hour of power for Midwest buyers in a region whose focal point is a trading hub in southern Ohio near Cincinnati hit a low of about $27 in July and late August because of unseasonably low temperatures and less use of air conditioners.
The high this summer was about $60 during mid-August, about the time of the blackout.
Typically, it costs a coal-fired plant, such as FirstEnergy's Bay Shore Road plant in Oregon, $20 to $30 to produce a megawatt-hour.
On any given day, according to the Intercontinental Exchange, buyers and sellers are constantly swapping as little as 100 megawatts or as much as thousands of megawatts.
Last Wednesday, a utility paid $38 a megawatt-hour for 200 megawatts of power delivered Thursday to a Western region trading hub centered near Mead, Nev.
That same day, 24 parties made 78 deals involving 66,400 megawatts to be delivered to the Ohio region, paying an average price of $27.86.
In five deals for electricity generated later in the evening when demand drops, buyers paid about $11.70 for each of 2,000 megawatts. The estimated value of the deals was $23,400.
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