Critics of Tennessee Gas Pipeline claim underused facilities already exist to meet need for additional natural gas

Last modified: Wednesday, July 08, 2015

The “need” for a proposed $5 billion natural gas pipeline scrutinized last month by state officials — and in the months ahead by federal authorities — is for a winter peak of just 30 to 40 days a year, argue a variety of critics of the Tennessee Gas Pipeline’s 430-mile Northeast Energy Direct project.

And those environmental groups, industry analysts, governmental agencies and independent researchers say a wealth of underused facilities are already available around New England to address the region’s needs before ratepayers are forced to pay for a new pipeline that could, they argue, drive gas prices up rather than down.

The pipeline project, which would cross Plainfield in Hampshire County and eight Franklin County towns on its route from Pennsylvania and then the Albany, New York, area and ultimately to Dracut, was proposed by the Kinder Morgan subsidiary to relieve pipeline congestion in New England, where pipeline capacity has not kept pace with dramatic increases in demand, the company says.

The arguments are among those made in three days of testimony last month before the state Department of Public Utilities in a case (DPU 15-48) involving a long-term contract by the Berkshire Gas Co. to buy the proposed pipeline’s gas.

Studies pointing to the need for added natural-gas capacity refer to peak days of the winter heating system, when gas-burning electric generating plants have had to pay a premium for fuel because gas-heating customers are given priority use of at-capacity pipelines.

The record cold during the first three months of 2014, for example, resulted in Massachusetts electric customers paying almost as much for power as they had spent in all of 2012, according to the region’s electric grid operator.

But while pipeline proponents say the reason New England has higher electric prices than places like neighboring New York is they have more gas pipelines, opponents point to price spikes on about three dozen days of winter as key to what’s needed.

“You only need the capacity 30 to 40 days a year, and you can satisfy those peaks with (liquified natural gas),” said Carol Churchill, a spokeswoman for GDF Suez North America, which owns the nation’s oldest LNG terminal in Everett, with two 180-foot-tall tanks that can hold 3.4 billion cubic feet of natural gas. (GDF Suez NA also is the parent of FirstLight, which owns the Northfield Mountain and Turners Falls hydroelectric plants.)

“If you build a pipeline, you can import cheap gas into New England, but you’re doing so in a very expensive pipeline, in a pipeline that’s subsidized. So there’s no incentive to size it correctly, there’s no incentive to hold down the gas. You’re bringing this cheap gas in on a very expensive pipeline, and you’re making consumers pay for it ... 365 days a year for 20 years whether they need it or not.”

The two LNG tanks, along with the Neptune Deepwater Port terminal that GDF/Suez owns 10 miles off the Gloucester coast, and two other offshore Gloucester terminals, fell largely into disuse since 2010, two years after opening in 2008, because LNG’s market price had a hard time competing with “hydrofracked” Marcellus shale gas.

The terminals played a larger role this past winter feeding generators. Part of that had to do with a reduction in LNG prices, and part of it was the result of improved planning by the region’s independent grid operator. But making better use of what GDF/Suez North America Gas operations Vice President Anthony Scargaggi says are the 45 LNG tanks around the region, with a total storage capacity of 20 billion cubic feet, could obviate the need for building new pipelines.

The immense capacity of gas that LNG tankers can bring in from Trinidad and the Mideast was described by attorney Rutilious “Rudy” Perkins III of Amherst in testimony to the DPU last month. LNG tanker Suez Matthew, which unloaded at GDF/Suez’s Distrigas terminal in February, holds the LNG equivalent of 2.6 billion cubic feet of gas — more than the daily capacity of the planned pipeline — while the tanker Excelerate, which unloaded at Gloucester’s Northeast Gateway in January, holds the equivalent of 2.8 billion cubic feet of gas as well as an onboard regasification unit.

“These huge cargoes amount to about three to four days of (a state-funded needs report) estimated peak statewide gas shortfall in 2030 in a single ship’s delivery. We only need to cover a few dozen days’ peak demand in a winter, the equivalent of maybe six to 10 LNG tanker loads, even if we did not adopt any of the other alternatives (like changing pricing structures) to reduce peak gas demand,” argued Perkins.

Although an LNG supply — bought on long-term contract — cannot be bought in time to meet a winter peak demand brought on by an extended cold snap like the Polar vortex in 2014, Scargaggi said, “We could bring in a ship every three days if we had to .... That’s about 3 BCf every day coming into the region. The infrastructure exists to be able to do that.”

Another underused resource regulators need to look at, say Perkins and other observers, are the kind of LNG storage tanks Berkshire Gas built in Whately in 1999.

Berkshire’s two 70,000-gallon tanks were specifically built for peaking — on a concrete pad with room for three more tanks to be added around 2003, 2011 and 2018.

“According to the Massachusetts Energy Facilities Siting Board in 1999, ‘Berkshire (Gas) stated that the proposed (Whately) LNG storage and vaporization facility would make it possible to ‘maintain adequate operating pressures during peak or near peak periods’ for the next 20 years,” Perkins told the DPU. “Three missing 70,000-gallon LNG tanks, by my math is 17,355 dekatherms of missing gas, enough to supply 200 percent of the average daily use of an additional 4,000 residential customers for roughly eight days ... That could be significant for winter peak periods, and winter peak capacity issues are often what can determine if new customers can be reliably served or not.”

Berkshire Gas spokesman Christopher Farrell told The Recorder in April, “We’ve looked at every possible option,” to avoid imposing a moratorium on new gas hookups because of constrained pipeline capacity. “We’ve looked at expanding our LNG facility in Whately, but the world market price for LNG is not at all attractive, number one. Number two, you never, never fuel baseload with a mechanical system, because it doesn’t offer the same reliability that pipeline gas does.”

Jennifer Boucher, manager of regulatory economics for Berkshire Gas, told the DPU last month, “Over the last 15 years, the company has ... gained valuable experience with respect to LNG operations that it did not have prior to the installation of its facility. A fully-expanded LNG facility would only provide a maximum additional volume of 5,000 Dth/d. The NED project, as currently proposed, would initially provide more than 20,000 Dth/d of deliverability to the Eastern Division for firm customers (which could be expanded), while simultaneously providing unmatched reliability benefits by providing a secondary major pipeline feed into this area.”

Others point out that LNG has played a key peaking role in New England for decades.

“Do we have to buy a big new car so Berkshire can have a hubcap?” Deerfield Energy Resources Committee member David Keith asked the state Department of Public Utilities at its Greenfield hearing last month. “The excess capacity of NED matters because it has to go somewhere else. NED is clearly about getting the tremendous glut of supply in the Marcellus shale region to markets willing to pay for it. Yet while growth in demand here is between 1 and 2 percent, NED adds 90 percent more gas. New England cannot use this much more gas.”

“The issue really is supply,” said Scargaggi. “There’s a confluence of things going on right now. You had this really cold winter two winters ago that nobody prepared for that caused substantial spikes in power prices that were real. Those currents caused a lot of uproar, caused a lot of players to come together in a way to benefit themselves, knowing that there’s a huge amount of natural gas that can be exported. You have the pipeline players who just make money because they put a pipeline in the ground. ... You put all that stuff together and you come up with a mind-set where, ‘If we can get somebody else to pay for this pipeline, we’re all OK.’ And we’ve got this consumer here who’s scared out of his wits, because he’s paid the most he’s ever paid in electric prices. The only one who’s bearing all the risk will be the consumer.”

Instead of the state looking into changing the rules so that electric utilities could make long-term investments in gas pipeline projects and then building those long-term gas contracts into their rate bases, Perkins suggested that the Department of Energy Resources investigate the possibility of creating a publicly owned natural gas and LNG stockpiling reserve for New England similar to the federal strategic oil reserve.

Responding to the DPU investigation into allowing utilities to invest in pipeline buildout, Assistant Attorney General Christina Belew testified last month, “Reducing winter demand for pipeline gas through a variety of methods may turn out to be far more economic than obligating Massachusetts ratepayers to pay for long-term contracts for firm transportation on a new pipeline and/or additional expanded pipelines.”


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