The different structures of the natural gas and power markets, disparate scheduling cycles and interstate natural gas pipeline constraints are the chief barriers to the efficient coordination of the two markets in the Northeast, regulators and industry officials said Monday.

The Northeast “is facing the issues of gas/electric interdependency more sharply and with more urgency than any other region due to [its]…strong dependency on natural gas both for electric generation and for home heating and other end uses,” said FERC Commissioner Cheryl LaFleur at a technical conference sponsored by the Federal Energy Regulatory Commission (FERC) in Boston. It was the second technical conference this month to explore issues related to the coordination of the two markets; a third conference is scheduled for Thursday.

“We in New England feel the gas and electric problems with particular urgency. We hope it’s not true, but we’re concerned we may be the canary in the coal mine,” said Ann Berwick, chair of the Massachusetts Department of Public Utilities. “On the bright side, we canaries work especially well together. The Northeast states are used to highly functional regional cooperation [on] various energy issues.”

Elizabeth Miller, commissioner of the Vermont Department of Public Service, said “we need to explore the governance needs and opportunities for addressing these problems at the regional level.”

The New England Independent System Operator (ISO) has taken the leadership on the coordination issue so far, but Miller called for action from the industries and states. “It’s clear that the ISO alone cannot come to the solutions [for] the region by itself,” she said.

The Northeast region — Connecticut, Rhode Island (RI), Massachusetts (MA), New Hampshire, Vermont and Maine (ME) — has an installed generation capacity of 37,943 MW, of which 45% is fueled by natural gas supplied by interstate pipelines, liquefied natural gas facilities and from Canada. The largest regional consumers of gas for generation are RI (98%), MA (59%) and ME (51%).

In seeking to help power generators achieve better coordination with gas pipelines, LaFleur cautioned that “we can’t compromise the reliable delivery of natural gas, particularly in the winter heating season.”

However, she said changes will be required of both markets. “I don’t think all the changes will be on the electric side. I expect the gas market to [fully] evolve to reflect this new and important customer base.”

James Ginnetti, senior vice president of external affairs and markets for EquiPower Resources Corp., said his company supports the New England ISO’s proposed change for day-ahead clearing. As it stands now, he said, a generator like EquiPower has to buy its gas somewhere between 9 a.m. and 10 a.m., then bid into the day-ahead market at noon, in advance of scheduling capacity on an interstate gas pipeline and knowing their commitments for the following day.

EquiPower and other generators in the Northeast do not find out until 4 p.m., when the day-ahead market clears, “whether they bought maybe the right amount of gas, maybe too little, maybe too much. If [there is] either too little or too much, they have to go into a relatively illiquid market and either buy more or sell what they over-bought.

“So we think it’s [ISO’s proposed change] a big improvement. [It] would help us know our commitment in the electric market before we have to go out and buy our gas and then schedule it timely at 12:30 p.m. [Eastern]. We think that’s a much better use of the limited infrastructure pipeline that we have,” Ginnetti said.

With the existing bidding and scheduling system, the risks are on the volume side rather than with prices, he noted. The change proposed by New England ISO would carry with it “some price risks.” The Northeast generators are split as to whether the movement of the day-ahead as the ISO has suggested is a good thing or a bad thing. “We think it’s a good thing,” Ginnetti said.

While scheduling is a pressing coordination issue, “we think it’s more of a physical infrastructure issue,” said John Rudiak, director of energy services for Connecticut Natural Gas Corp. and Southern Connecticut Gas Co. He noted there is only 2.7 Bcf/d of forward haul pipeline capacity into the region, which has led to significant constraints.

He noted that Algonquin Gas Transmission last winter had 100 days of restrictions on its system, preventing the scheduling of gas. Tennessee Gas Pipeline also had restrictions on its system in New York 99% of the days last winter. Rudiak said that Tennessee in the last five quarters has reported 30 operational flow orders, 24 of which were directly related to gas usage in power generation.

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