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In New England, a Natural Gas Trap

Matthew L Wald, New York Times, Feb 15 2013

Electricity prices in New England have been four to eight times higher than normal in the last few weeks, as the region’s extreme reliance on natural gas for power supplies has collided with a surge in demand for heating.

Frigid temperatures and the snowstorm that hammered parts of the Northeast last week have revived concerns about the lack of alternatives to natural gas. Many plants that ran on coal or oil have been shuttered, and the few that remain cannot be put into service quickly enough to meet spikes in demand. The price of electricity is determined by the price of gas.

Last year, natural gas provided 52 percent of New England’s electricity, and that share is expected to grow. Gas is generally cheaper than other energy sources, and the lower costs have spurred the retirement of aging coal generators and nuclear reactors. The six-state New England region and parts of Long Island are the most vulnerable now to overreliance on gas, a vulnerability heightened by a shortage of natural gas pipeline capacity, but officials worry that similar problems could spread to the Midwest.

“We are sticking a lot of straws into this soft drink,” said William P. Short III, an energy consultant whose clients include companies that move and burn gas. “This is a harbinger of things to come in New England, as well as New York.”

James G. Daly, vice president for energy supply at Northeast Utilities, a company that, through its subsidiaries, provides electricity to homes and businesses in Connecticut, Massachusetts and New Hampshire, said: “There is concern we don’t have enough capacity to supply heating and electricity generation.”

Northeast and many other companies are temporarily insulated from the spot market because they sign long-term contracts for electricity supply. But Northeast’s energy charges next year could be 10 percent higher than they are now, Mr. Daly said, because the companies that sell power on a long-term basis will charge more to absorb the risk of short-term spikes in prices.

“It is certainly true that a region like New England that relies on a single fuel source like natural gas for the bulk of its power does leave itself open for more disruptions than a region with a more diverse fuel mix,” said Jay Apt, executive director of the Electricity Industry Center at Carnegie Mellon University in Pittsburgh. “It’s not a knock against natural gas; it’s a knock against a single fuel source.”

The American Public Power Association has warned since 2010 that demand is outpacing the delivery capacity of gas infrastructure. At coal plants, “you can look out the window and see that 60-day supply of your fuel,” said Joe Nipper, the group’s senior vice president of government relations. But gas plants tend to deliver fuel just as it is needed.

The gyrations of the spot market are hard to follow because prices are set in units few consumers understand. Electricity is sold on the wholesale market in megawatt-hours, or thousands of kilowatt-hours; a megawatt-hour is enough to run a big suburban house for a month. Natural gas is sold in a unit called an MMBtu, or a million British thermal units. An MMBtu equals 10 therms, the unit home heating customers pay for.

Normally, a megawatt-hour costs $30 to $50, and an MMBtu less than $4. But not lately.

The problem began late last year. During a cold snap around Thanksgiving, electricity prices in New England shot up to the highest in the country: $103.20 per megawatt-hour and $12.37 per MMBtu on Nov. 27.

On Jan. 24, the cost of an MMBtu of natural gas at Algonquin Citygate, a spot near Boston where gas is traded, rose to $31.20, pushing the price of a megawatt-hour over $200. Constellation Energy, which operates plants in the region, attributed the jump to temperatures 15 to 20 degrees below average.

A megawatt-hour cost about $150 early this month, according to weekly reports from ISO New England, the independent operator that maintains the region’s electricity market. A year ago, the price was around $30.

New England’s problems have been moderated somewhat by imports. “Without Indian Point, New England would have been toast,” Mr. Short said. “We’re importing 1,400 megawatts out of New York.” Indian Point is a twin-unit nuclear plant on the Hudson River that New York State is seeking to close.

But the region is littered with 1950s- and 1960s-era coal and oil plants that have been retired in the last few years. The 214-megawatt, coal-fired AES Thames unit near Uncasville, Conn., shut down in 2011; Somerset Station, a 174-megawatt, coal-fired plant in Somerset, Mass., closed in 2010.

The Salem Harbor plant in Salem, Mass., once had four coal and oil units, with a capacity of 745 megawatts. Two have closed, and the others will probably close next year. A new owner intends to build a 630-megawatt plant that will run on natural gas.

The underlying issue in New England is that gas pipeline capacity is inadequate to keep prices steady in times of high home heating demand, said Vamsi Chadalavada, executive vice president and chief operating officer of ISO New England. ISO is leading a study focused mainly on reliability, but reliability is intertwined with price, he said.

Importing liquefied natural gas would help, Dr. Chadalavada said, but cargoes are going instead to Europe and South America, where prices are higher.

Several companies want to liquefy and export gas from the continental United States because of the shale gas glut, and the events in New England could affect that debate. Opposition has come mostly from domestic industries that use the gas. A spokesman for Senator Ron Wyden, Democrat of Oregon and chairman of the Senate Committee on Energy and Natural Resources, said Mr. Wyden saw the price gyrations in New England as a reason to “look before we leap ahead with unfettered exports of gas.”

But the biggest problem may be the inadequacy of existing pipelines. On Feb. 7, ISO New England told the Federal Energy Regulatory Commission that it was concerned about “increasing reliance on natural gas-fueled generators at times when there is an increasingly tight availability of pipeline capacity to deliver natural gas from the south and west to New England.”

Additionally, experts say that the natural gas market and the electric market mesh poorly, because while the electric market runs around the clock, the gas market closes down at night.

During the storm last week, with transmission lines being knocked out by snow and high winds, ISO asked some gas-fired generators to start running in the middle of the night, Dr. Chadalavada said, and found they could not. “We were sitting here, 3 in the morning, trying to get gas generators to start up, and we started seeing where they couldn’t access that market in the overnight hours,” he said.

About 30 percent of the generators in the region burn coal and oil, Dr. Chadalavada said, but they produce less than 1 percent of the energy because they run so seldom. Some can take 24 hours to return to service.

ISO and the Federal Energy Regulatory Commission, which oversees interstate electricity and gas markets and transmission, are trying to make the systems mesh better.

Source

Natural Gas

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