By Michael Kuser

WESTBOROUGH, Mass. — New England will have only enough natural gas capacity to supply about half of its gas-fired generation in winters 2025 and 2030 in most scenarios, according to an analysis presented to the ISO-NE Planning Advisory Committee on Thursday.

Mark Babula, ISO-NE system planning manager for resource adequacy, said the study showed the region will have sufficient pipeline and LNG capacity to supply all the gas generation with capacity obligations during the summer. But in the winter — when generators must defer to firm gas heating customers — the region won’t have sufficient capacity under most circumstances to run all the gas generation that could be economically dispatched.

“When we’re talking about dispatch, what we’re looking at from the natural gas system perspective is meeting the contractual requirements to the [local distribution companies],” said Michael Henderson, ISO-NE director of regional planning and coordination. “That then gives you some extra gas available that can potentially serve natural gas-fired generation. It’s just different looks at how much natural gas-fired generation can be brought on.”

The ISO-NE study considered six natural gas system topologies and six “resource expansion” scenarios to determine whether there is sufficient “spare” gas for electric generation after meeting all firm customers’ needs:

• Installed Capacity: All gas-fired generation with capacity supply obligations — a summer focus that represents the upper band of gas consumption by the electric sector. Even under the minimum gas infrastructure case, there is enough spare gas to fuel all gas-fired generation in the summers of 2025 and 2030, but there is only enough spare gas in the winters to serve about half of the gas-fired installed capacity.
• Dispatched Capacity: Gas-fired dispatched capacity requirements on the winter peak gas day, when only a portion of installed gas capacity is needed to serve electric demand.
• Energy Generation: Whether there is enough gas to satisfy the maximum hourly electric energy production by gas-fired generation on the summer and winter peak gas-days. The analysis found sufficient gas for all summer generation needs. For winter 2025, however, there would be sufficient gas for only 6.8 to 9.6 GW of generation, representing 42 to 59% of the projected installed capacity. By winter 2030, the gas could run between 5.3 and 10.1 GW — as little as one-third of the installed capacity.

Only one of six resource expansion scenarios (“Renewables Plus”) meets the dispatched capacity and energy generation requirements for winters 2025 and 2030, even assuming the “maximum gas infrastructure” — reflecting pipeline expansions, increased peak shaving by LDC, and LNG from offshore and ENGIE’s Distrigas terminal in Everett, Mass.

“In the summertime, we’re good. There’s actually leftover gas: We could actually run another 12,000 to 15,000 MW, there’s so much excess pipe available,” Babula said. “When you get into those polar vortex sort of days, we often hear from generators that have just been called by the gas pipe to get back on their ratable take and shut off the valve.”

Babula pointed out that the analysis studied only winter and summer peak days. ISO-NE is also conducting a Fuel Security Analysis that will quantify the operational risks of insufficient fuel for the entire 90-day winter period. ISO-NE on May 22 published a summary of the analysis, which is expected to be completed this fall.

While the RTO’s analysis looks at the system’s maximum, short-term capability, the ISO-NE study will determine how often the system likely to be stressed during the winter under different scenarios.

LNG’s Role

LNG from Distrigas, the Canaport terminal in Saint John, New Brunswick, and offshore floating storage regasification units are critical for meeting the peak gas-day requirements of the electric sector, according to the study. Without these gas supply sources, approximately ~1.5 Bcfd (~214,300 MWh/d) would be taken out the market.

Management consultant Richard Levitan asked whether the floating storage wouldn’t better be classified as a commodity, considering how inflexible the arrival of LNG carriers can be. Babula said that in the past couple years there have been “ships at the buoy” on most peak gas days, so they included them in the study.

[EDITOR’S NOTE: An earlier version of this article mistakenly said the analysis was conducted by the New England Power Pool. It was conducted by ISO-NE.]

Six Resource Expansion Scenarios

The resource expansion scenarios were:

• • • S1 = RPS + Gas: Physically meet renewable portfolio standards and replace generator retirements with natural gas combined cycle units.
    • S2 = ISO Queue: Physically meet RPS and replace generator retirements with new renewables and clean energy.
    • S3 = Renewables Plus: The region retires older generating units, physically meets all state RPS and adds renewables/clean energy, energy efficiency, solar PV, plug-in electric vehicles and storage.
    • S4 = No Retirements (beyond FCA 10): Meet RPS with new resources under development and use alternative compliance payments (ACPs) for shortfalls. Add natural gas units.
    • S5 = ACPs + Gas: Meet RPS with new resources under development and use ACPs. Replace all retirements with natural gas units.
    • S6 = RPS + Geodiverse Renewables: Scenario 2 with a more geographically balanced mix of on/offshore wind and solar PV.