By Michael Kuser

BOSTON — Growing solar generation will be able to meet a third of peak load in Massachusetts in a few years, but as the grid is reaching the saturation point in certain areas, policymakers are looking to energy storage to help address some of the challenges.

“The grid was not initially designed for this much distributed energy … and we never envisioned 90,000 power plants out there,” Commissioner Judith Judson of the Massachusetts Department of Energy Resources said Friday at the 160th New England Electricity Restructuring Roundtable run by Raab Associates.

Judson said the state now has more than 89,000 installed solar projects totaling more than 2,300 MW in each of its 351 cities and towns.

On Nov. 26, it launched the Solar Massachusetts Renewable Target (SMART) program, which provides incentives for projects on brownfields, landfills, parking lots and rooftops. “SMART provides a fixed revenue stream to reduce the cost of the program, and we are the first state in the nation to have a solar-plus-storage incentive,” Judson said.

It took the state a long time to launch the program because “we have a regulatory process in DOER and in the Department of Public Utilities, plus heavy stakeholder engagement,” Judson said. “But we’ve had over 2,850 applications for 650 MW in capacity submitted so far and $4.7 billion in cost savings to ratepayers compared to earlier solar programs, so I think it’s made for a better program.”

On Dec. 12, the state issued its Comprehensive Energy Plan (CEP), including a provision for the state’s utilities to procure a combined 200 MWh of energy storage by 2020. (See Massachusetts Deploys Utility-Scale Energy Storage.)

Transition in Connecticut

“The grid modernization proceeding [Case 17-2-03] in Connecticut is a really promising opportunity,” said Mary Sotos, deputy commissioner of the state’s Department of Energy and Environmental Protection.

“I think it’s the first time utilities have laid out for the public … how they’re doing manual, back-end system work for stuff they want automated at scale,” Sotos said. “It’s not just the cost of the meters for them; the concern is managing the data … putting it in the right format, which is all part of this broader shift in information availability.” (See Connecticut Explores its Energy Future at CPES Event.)

Sotos highlighted “opportunities to align policy objectives, customer objectives and developer objectives.”

Connecticut’s solar programs are all in transition, including ones that limit virtual net metering for state, municipal and aggregation customers by capping the amount that could be reflected into rates, she said.

Connecticut last spring passed a bill that doubles the amount of renewable energy utilities must use to serve load — 40% by 2030 — while also revoking net metering guarantees that ensured rooftop solar owners earn retail prices for their excess electricity. (See Connecticut Energy Bill Draws Mixed Reviews.)

“Net metering was available to all these customers in the past on the energy side to compensate solar energy … and each of those solar programs had a statutory spending cap, but we found that municipalities were reaching that cap very quickly,” Sotos said. “For each of these groups we also had a separate program to help facilitate the deployment of behind-the-meter solar by focusing on the RECs [renewable energy credits].”

The state’s Green Bank ran “an incredibly successful” residential solar investment program to focus on the RECs from installations with storage, she said.

“However, under the current monthly net metering model, there isn’t an obvious incentive for customers to do storage, because any energy that is excess or used in real time, it’s all valued at the same level,” Sotos said. “From our perspective, to really value storage for dynamic peak reduction or other benefits … there needs to be an additional financial signal, whether that’s a time-of-use rate or some other type of adder.”

Field Experience

Jonathan Raab of Raab Associates, who has been convening the roundtables since 1995, said he was lucky in his selection of two of last week’s panelists: Evan Dube, senior director of policy at SunRun, represented the most megawatts bid in the under-25-kW category in the SMART program, while Ilan Gutherz, senior director of strategy and policy at Borrego Solar, represented the most megawatts bid in the over-25-kW category.

“Having a robust [distributed energy resources] market, both behind-the-meter and in front, is going to be critical for sustaining the grid in the future,” Dube said. “We hear an awful lot about how rate design must be sustainable … but in so doing, we have to keep in mind the benefits that building out these resources will have in the long term, and how that’s going to make us more sustainable in the future.”

More granular rate design such as time-of-use rates is preferable because it is fairer to customers, but that rate structure is contingent on penetration levels and their location, which affect the price of electricity, Dube said. The availability of metering infrastructure and data also influence how exact electric power billing can get.

The future of compensation for zero-marginal-cost resources like wind and solar depends on getting regulators to “think about how PV and batteries can avoid the need for long-term transmission investment,” Gutherz said.

New York’s Value of DER tariff that large-scale solar and other resources are now on has been testing value-based compensation as opposed to cost-based compensation alone, he said.

“New York’s an interesting experiment; in our opinion, they went a little bit too fast, so if you watch the recent filings from the commission there, you’ll see there’s been a lot of back-pedaling on certain aspects of that tariff,” Gutherz said.

“Solar plus storage is a game-changer,” said Juliana Mandell, director of market development and policy at ENGIE Storage. “You’re transforming solar into a dispatchable, reliable renewable energy resource that’s no longer time-constrained, and that fundamentally shifts the conversation.”

Energy storage can flatten load and generation, be used to reduce peak demand, or to shift generation and load depending on grid system needs and economic signals, she said.

“And you can use storage to mitigate locational constraints and congestion [and] improve capacity supply, and storage can participate at a high level in the wholesale market,” Mandell said. “You can see that coming out of the recent FERC orders if you’re looking [at] how do we pay fairly for resources that provide a different level of performance.”

“The questions is not why solar, but why distributed solar?” said Jesse Jenkins, postdoctoral fellow at Harvard’s Kennedy School and one of the contributors to the MIT Utility of the Future study. “Solar and storage are technologies and means that deliver value, so what we need to focus on is the ends that we have in mind and the value that we want to capture. … Solar and storage are not the only ways to deliver any of the values we’re talking about.”

Mark LeBel, an attorney with Acadia Center, said that solar, peaking in summer, has to be balanced with winter-peaking wind, but that balance is also needed to value societal concerns.

Rooftops almost certainly have to be part of the answer for solar, because there are little or no siting issues, he said.

“Where are we going to put 20 GW of solar?” LeBel said. “Does New England want to pave over paradise?”