Natural Gas In New England

We’ve gotten used to our local electric utilities asking us to ease up on the air conditioning and turn off unneeded lights during hot summer months. In the Northeast
(especially New England), those requests are becoming even more urgent in the winter. With more electricity coming from natural-gas-based generators and more homeowners converting from oil to gas-heating systems, supplies are becoming stretched and electricity prices are rising quickly.

The potential severity of supply shortfalls became frighteningly clear last winter when a January cold snap and a February nor’easter strained capacity, pushed generator costs to a 10-year high, and tripled wholesale electricity rates over 2012’s same-period figures. This winter, New England customers of at least one large local utility, National Grid, will be paying 18 percent more per kilowatt-hour for electricity than they did last winter, and the problem looks to get worse before it gets better.

In the last decade or so, natural gas has come to dominate New England’s generation portfolio, now totaling more than 50 percent of all megawatt-hours generated. Initially, this meant much less expensive electricity, since natural gas power plants were replacing old, inefficient (and very dirty) coal- and oil-fired facilities. Now, though, the growing demand is beginning to push prices up, with higher rates yet to come. Several more coal plants, along with the 600-megawatt (MW) Vermont Yankee nuclear plant, are set to close within the next two years. The majority of that lost capacity will be picked up by new natural gas plants, driving demand even higher.

Of course, natural gas offers many advantages: it is much cleaner burning than oil or coal (the region’s air is already seeing benefits), and, thanks to the current shale boom, there’s plenty of natural gas on the market. The problem lies in getting that gas from central market locations to the generating plants, and solving that conundrum will require both more capacity and a closer look at the varying ways gas companies sell their product and electricity generators buy it.

“Fundamentally, it’s a lack of adequate pipeline capacity,” said Peter Abt, managing director of the Oil & Gas Strategy Practice of Black & Veatch, an engineering firm that builds pipelines, among other major infrastructure components. 

He noted that the two pipelines currently serving the region, the Algonquin Gas Transmission System and the Tennessee Gas Pipeline, were sized to serve projected heating demand on the coldest day of the year, and they are scrambling to meet the added needs of an increasing number of electricity generation plants. 

“The challenge is [generators] really only need that capacity 30 to 60 days a year,” Abt said.

And this is where we start to get into the complicated differences between the natural gas and electricity markets, especially in markets as deregulated as those in New England. Local gas distribution companies often lock up their deliveries months in advance, and those long-term contracts assure pipeline developers (and their bankers) that a new line will be profitable. However, merchant (i.e., nonutility-owned) electricity generation plants are used to buying fuel on a day-ahead basis because they can’t predict when demand will make it most economically beneficial for them to bid their production into the market. Additionally, natural gas markets for the next day close before next-day electricity markets, which means electricity generators can be stuck bidding into a next-day power market without knowledge of whether they will have adequate natural gas supplies to meet their production obligations.

Some now are arguing that tying gas and electricity markets more closely to each other could be a good first step to help prevent price spikes like the increases that occurred last winter, when generators scrambled to get whatever gas they could to meet the production targets to which they had obligated themselves. In other times, such spot purchases are less difficult; but, during a cold snap, when distribution companies have little extra gas to spare, what there is can become very expensive.

“It drove the price of the capacity that was available to really high numbers,” said Peter Weigand, founder and CEO of the Boston-headquartered energy-markets consulting firm Skipping Stone. He added that coordinating gas and electricity trading days would allow the regional independent system operator to confirm a generator actually had the fuel on-hand to meet its production obligations. 

“[Right now,] they take it on faith the generator actually has the supply,” he said.

Though market coordination could help, Abt is firm that, in the end, new capacity will have to be built to meet New England’s growing demand. However, the question of how new pipelines will be paid for remains the sticking point. Developers are reluctant to break ground without firm purchase contracts, and generators are reluctant to commit to purchases they might not need. Whatever arrangements are made, businesses and homeowners won’t be seeing wintertime rates fall any time soon.

“The consumer, ultimately, will be bearing the cost,” Abt said.

About the Author

Chuck Ross

Freelance Writer
Chuck Ross is a freelance writer and editor who has covered building and energy technologies for a range of industry publications and websites for more than 25 years. He specializes in building and energy technologies, along with electric-utility bus...

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