The president of New England's largest distributor of liquefied natural gas says the region's governors are barking up the wrong tree in calling for a ratepayer-funded pipeline to expand the flow of natural gas into the six states.
Pipeline capacity is really only a problem during the 15 to 40 coldest days of the year, and could be addressed by deliveries of LNG to power plants fueled by natural gas, says Francis J. Katulak, CEO of GDF Suez, which operates the Distrigas terminal in Everett, Mass.
"The region needs to think about utilizing the existing infrastructure and assess what the real need is before we build out the pipeline system," he said in a recent interview.
GDF Suez is in the business of selling LNG, so it's no surprise the company would try to slow down a headlong rush for new pipeline capacity. More natural gas flowing into New England via pipeline could mean less demand for LNG that arrives by ship.
Once those ships dock at Distrigas, the liquefied fuel is converted back to gas and pushed into the same pipelines that carry natural gas from west to east.
That east-to-west flow, which is possible because the pipelines are empty by the time they reach the East Coast, has been used to serve peak power needs in the past, and could do so in the future if power plant owners or the grid operators were willing to purchase the LNG ahead of time, Katulak said.
He uses an analysis of "Options for Serving New England Natural Gas Demand," commissioned by GDF Suez and completed late last year, to make his point.
The analysis documents that pipeline capacity into New England is sufficient except for an average of 30 days each year, during which time "incremental LNG imports at Distrigas appear to be the most cost-effective solution."
While Marcellus-area gas is attractively priced, the report notes, a new pipeline to connect New England to the Marcellus Shale would cost about $2 billion.
"Since the additional capacity would have to be fully contracted, but needed only about 30 days per year, the per-unit cost of this option is relatively high, at $16 to $20 per MMBtu," the report states. "The landed price of LNG at Distrigas is likely to be less than $15 per MMBtu."
That's too high to be competitive most of the year, but at crunch time, compared to some of the spot prices this past winter, $15 would be a bargain.
The barrier to an LNG solution is the same barrier that's blocking pipeline construction — something policy experts call "market design," which means there are no incentives for power plant owners to make long-term commitments to buy either LNG shipments or pipeline capacity, so we get neither.
Instead, gas-fired plants operate when it is economical for them to do so, and shut down when it isn't, leaving grid operators to deploy coal-fired generation that is rarely used otherwise.
ISO-NE is trying to address the problem through new "pay for performance" incentives that may not be in place until 2018, given the lengthy stakeholder process, regulatory review and possible court challenges by power plant owners.
The region needs a bridge to 2018, when pipeline capacity is likely to be expanded one way or another and a new market design is in place. LNG could be that bridge, but it hasn't even been a big part of the discussion.
Katulak blamed ISO-NE for that, in part, because the grid operator doubled-down on oil, instead of LNG, as a backup fuel for the anticipated problems this winter.
By stockpiling oil, ISO was able to keep the electrons flowing even when most of the natural gas plants were idle due to high prices.
Katulak said ISO-NE, whose main responsibility is to maintain grid reliability, should be "fuel neutral" when it comes to backup strategies, and should go with the lowest price, as it does on a daily basis in the wholesale market.
He believes LNG would have competed favorably with coal on price for peaking power this winter, but that ISO was concerned about the impact on gas prices of a large LNG procurement.