A lot of gas, but not here: How should New England deal with its natural gas appetite?

Posted Jan. 23, 2014, at 12:32 p.m.
Last modified Jan. 23, 2014, at 4:05 p.m.

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A warning sign for a natural gas pipeline is seen at an oil pump site outside of Williston, N.D.
SHANNON STAPLETON | Reuters
A warning sign for a natural gas pipeline is seen at an oil pump site outside of Williston, N.D.

The agreement among the six New England governors to invest as a region in new natural gas pipeline capacity and electric transmission is rooted in part in cold days like many that Maine and the rest of New England have experienced so far this winter.

It’s also part of a gradual shift in the region away from coal, oil and nuclear energy toward greater natural gas dependence and rising demand for renewable energy.

Under the preliminary energy agreement, ISO New England, which operates the New England electric grid, would purchase 600 million cubic feet in new natural gas pipeline capacity and request proposals for new transmission lines that would likely transport renewable energy — such as Maine wind — to the more populous states demanding it.

Cold weather, pricey electricity

Record-breaking cold stretches this winter have posed an electricity price problem for New England. That’s because the region’s limited network of natural gas pipelines becomes especially stressed on the coldest days when demand for gas is highest.

New England has derived a growing portion of its electricity from natural gas since 2000 as the fuel has become cheaper and more plentiful; 52 percent of the region’s electricity came from gas in 2012, up from 15 percent in 2000.

But local natural gas utilities that deliver gas to homes and businesses for heating — not electric generators — generally lay first claim to the gas coming into the region. Those utilities sign long-term contracts with pipeline developers for pipeline capacity; electricity generators don’t.

On cold days, when the demand for gas heat surges, gas utilities take large portions of the gas to which they’ve subscribed, leaving less and more expensive gas for electric generators.

“The challenge is, in New England, this problem is really focused on just three months, all when it’s cold,” said Patrick Woodcock, Gov. Paul LePage’s energy director. “That’s when prices spike.”

On Thursday, as cold temperatures persisted across Maine, New England’s daily spot price for gas rose to $77.60 per million British thermal unit, or MMBtu, compared with $4.92 in Louisiana, home to the trading hub that sets the nation’s benchmark price. The price difference was even more pronounced in New York City on Wednesday, when the price shot up to $120.75, according to the Energy Information Administration.

The price of electricity closely tracks those natural gas price spikes. Wednesday’s electricity price for New England was 43.8 cents per kilowatt hour; New England’s average in 2012 was 14.02 cents per kilowatt hour, according to EIA data.

This winter has seen a number of days with especially cold weather that has forced New England’s natural gas — and thus electricity — prices significantly higher than their averages. The region’s daily electricity mix has changed as a result; it has come to rely more heavily on coal and oil this winter in the absence of cheap natural gas, according to ISO New England.

Would it be enough?

The idea behind New England’s regional purchase of new gas pipeline capacity is to ensure the construction of new pipeline that can make more cheaply priced gas readily available to the region’s electric generators.

Each state’s ratepayers would fund a proportional share of the investment, with Maine likely responsible for about 8 percent — the state’s share of the region’s electricity demand.

Regional energy officials say they also want to chip away — if not eliminate — the gas price difference between New England and Louisiana’s Henry Hub. That price disparity is called the basis differential.

“From Maine’s perspective, it’s good to get our prices looking like what prices look like elsewhere in the country,” said Tom Welch, chairman of the Maine Public Utilities Commission.

With their pipeline capacity purchase, the New England states would be looking to build on the added capacity from one pipeline expansion project, Spectra’s Algonquin Incremental Market project, that’s already pending for the region. That project, which is slated to be completed in November 2016, would add capacity to an existing pipeline that runs from New Jersey to the Boston area.

A natural gas price analysis recently commissioned by the Maine PUC predicted that Spectra’s 350-million-cubic-feet-per-day addition would cut New England’s basis differential by almost a third.

“Increasing capacity lowers costs,” said Woodcock. “It also gives you a sense of how much [more capacity] do you need.”

But another 600 million cubic feet per day of pipeline capacity will fall well short of what the region needs, said Tony Buxton, senior counsel to the Industrial Energy Consumer Group, a Maine industrial group that represents some of the state’s mills and other large energy users.

IECG has calculated the region needs 2 billion cubic feet per day of additional pipeline capacity to eliminate the basis differential.

“It is extremely puzzling why the governor’s energy director would not want a complete solution to this problem or even want to have the flexibility to respond quickly if the 600 number is inadequate,” Buxton said.

Woodcock acknowledged the region might need more pipeline capacity. “It’s more modest than I think we may ultimately require,” he said. It’s “a modest, sensible step.”

Changing energy dynamics

While New England’s energy officials take steps to bring more natural gas to the region, the region’s energy picture is changing in other ways that could complicate the natural gas math.

Demand for natural gas by the region’s electric grid is unlikely to let up, especially as the region braces for the retirement of a number of coal- and oil-powered generators in the coming years. ISO New England anticipates up to a fifth of the region’s generating capacity could be retired in a three- to eight-year time span.

At the end of this year, the region will lose one of its four remaining nuclear power plants when Vermont Yankee shuts down.

And just as the region’s electric grid grows more dependent on natural gas, natural gas demand for home heating is also likely to grow, potentially limiting supplies for electric generators if the region doesn’t add enough pipeline. In Connecticut, for example, state regulators have approved a plan to convert 280,000 homes to natural gas heat.

“Right now, the pipelines are absolutely running flat-out,” said Welch. “What we want to see is a situation where, even in the winter, they have excess capacity on them.”

At the same time, the New England states will demand more electricity from renewable sources — five of the six states have laws on the books that require a greater percentage of electricity to come from renewable resources — and potentially large-scale hydropower from Canadian resources in Quebec and Newfoundland and Labrador.

Utilities in Massachusetts and Connecticut, which are responsible for the bulk of New England’s demand, last year signed power-purchase agreements with developers planning wind turbine installations in Maine.

The power will need to get from the place where it’s generated to the place where it’s consumed. That means the region will need new transmission. While the region’s six governors ordered ISO New England to start the process for approving new transmission projects, officials from the six states say they aren’t yet committing to specific projects that have been proposed and, in some cases, caused controversy.

Similarly, state energy officials aren’t yet committing to a specific New England pipeline project.

“We are fairly agnostic on what project it is,” Woodcock said. “We’ve been focused on the results.”

Matthew Stone is BDN opinion page editor.

 

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