PROVIDENCE, R.I. — Offshore wind will soon be comparable in scale to other renewable energy resources such as onshore wind and solar, participants at the quarterly meeting of ISO-NE’s Consumer Liaison Group heard last week.

New England never had natural gas or oil and has always had to pay for energy imports, but the region’s luck is changing with offshore wind, said Jeffrey Grybowski, co-CEO of Ørsted US Offshore Wind.

“Offshore wind has no size constraints like there are onshore,” Grybowski said. He cited the ever-growing size of commercial wind turbines as proof: Siemens (8 MW), Vestas (10 MW) and General Electric (12 MW).

“Each one of these manufacturers tries to one-up the other,” he said. “The projects are getting larger, reducing costs, and Ørsted is now working on a 1.2-GW project off the U.K.”

The lucky break for the region is that big load centers along the Northeast coast match the location of the highest offshore wind generation potential, Grybowski said.

“In addition, New England super-peak days in winter coincide with what are normally the highest production times for offshore wind here,” he said.

On the solar front, Acadia Center projects the region, combined with New York, will have 24 GW of distributed solar installed by 2030, plus about 12 GW of utility-scale solar.

“The economics of siting solar farms is driving developers to large, flat, forested sections of land, and this isn’t Kansas,” said Erika Niedowski, the center’s Rhode Island director and policy advocate.

According to the state’s Energy Plan, Rhode Island could develop more than 1,800 MW of solar by 2035, compared to the current 105 MW. “But we need to be developing clean energy with a balanced approach, with environmental considerations,” Niedowski said.

Douglas Gablinske, executive director of the Energy Council of Rhode Island, joked about the increasing resistance among New Englanders to any kind of new energy infrastructure: “I’ll introduce a new acronym to the sector, NWN, for ‘nobody wants nothing.’”

Market Policy Debate

Anne George, ISO-NE vice president for external affairs, profiled the RTO’s activities and explained its work to enhance energy security. Prior to filing a long-term solution with FERC later this year, the RTO plans to imminently file an interim proposal for compensating generators for maintaining fuel inventories during winter, she said. (See related story, “RTO’s Interim Winter Fuel Proposal Rejected,” RTO Insider Reporter Admitted to NEPOOL.)

Under the proposal’s two-settlement structure, resources would be paid or charged for deviations between the inventoried energy purchased in a forward position for the entire winter season and the spot settlement rate — representing energy maintained during each trigger condition.

ISO-NE estimates the voluntary program will have direct costs of $112 million to $158 million a year. George noted that “the markets work together, so though this will be a payment through the energy market, when that’s dealt with in the capacity market the net cost is likely to be a lot less than that.”

The New England Power Pool Participants Committee on Wednesday rejected the RTO’s interim proposal, which would cover capacity commitment periods 14 (2023/24) and 15 (2024/25). Despite the proposal receiving less than 33% vote in favor, the RTO will move ahead with its filing. Members also rejected a proposal by energy services firm Energy New England (ENE) that would have limited compensation to oil and certain natural gas, demand response and electric storage resources.

Meg Lusardi, executive vice president of PowerOptions, the largest energy-buying consortium in New England, also questioned the RTO’s reasoning.

“The interim program … we refer to it as winter reliability on steroids,” Lusardi said. “The program failed to win passage at NEPOOL, though how that will affect decision-making at FERC is hard to say.”

PowerOptions signed on to a study by Synapse Energy Economics last May that showed the RTO’s January 2018 fuel security analysis to have been too conservative, which resulted in overplaying the risk of rolling blackouts, she said.

“There are cost impacts to customers with all of these market mechanisms that are going on, and it is complicated,” Lusardi said. “We all know that Mystic is being paid to run for 2022 to 2023, and maybe for 2023 to 2024, and this has been approved. The estimated cost for that is $200 million a year, so customers are going to have to take on that cost.”

George also mentioned that the RTO’s enhanced storage participation rules go into effect April 1, 2019. In February, FERC accepted Tariff revisions that enable batteries and other emerging storage technologies to more fully participate in the region’s wholesale electricity markets. (See FERC Accepts ISO-NE Storage Tariff Revisions.) But still pending before the commission is the RTO’s December 2018 filing that demonstrates full compliance with FERC Order 841.

Grid Transformation

Transformation of the Rhode Island power sector extends beyond grid modernization, said Jonathan Schrag, deputy administrator of the state’s Division of Public Utilities and Carriers.

“The larger power sector transformation … includes the work that the Office of Energy Resources is leading on procurement of clean energy resources … and the work that our Public Utilities Commission is leading on guidance for the way we do performance incentive mechanisms,” Schrag said.

The transformation also includes work his agency is taking on in collaboration with OER on non-wires alternatives, he said.

“We’re not just technology-agnostic, but hostile to any particular one” being pushed over any other, Schrag said.

Since the state deployed the bulk of its advanced meters between 1999 and 2003, most “are aging out now,” requiring state officials in the next few years “to make some critical choices around a very large distribution system asset.”

One strategy for the state is not so much “to promote electrification, but to optimize it,” he said.

“Rate design is a big deal,” said Timothy Hebert, COO of ENE, which serves municipal power companies. “What’s driving cost structures for customers is really changing. Around some of the new strategies that are being employed — distributed generation, storage — we’ve seen a lot of interest at the municipal utility level in developing electric vehicle programs.”

Regarding EV charging, Synapse’s Paul Peterson noted ISO-NE performed a 2016 economic study that showed one scenario with 3 million EVs in New England by 2030.

The RTO modeled the EVs to charge at night, “ran the model, and the problem was now the peak occurred at night,” Peterson said. “So then they told the model to charge the EVs at off-peak hours, and there was virtually no change to peak demand in the model, with or without the EVs, and the actual electrical energy used is not terribly significant.”

Data cannot be talked about enough, as there are so many additional layers of information to look at these days, Hebert said.

“We have a lot of different things happening … a dance going on every day.”

– Michael Kuser