by Jeff St. John
November 04, 2020

This is the fourth installment in a GTM Squared report examining the discrete paths toward distributed energy resource integration being taken by different states. Our first pieces dealt with California and New York, two states with ambitious clean-energy and carbon-reduction mandates, and Arizona, which is taking a more utility-centric approach to enlisting customer-owned DERs into its expanding decarbonization goals. 

Our series takes us now to Massachusetts, where lawmakers, regulators and utilities have embraced a more idiosyncratic approach to incentivizing solar, batteries, smart thermostats and electric vehicles to match the needs of a clean-powered grid. That’s allowed the state to avoid some of the behind-the-meter bottlenecks faced by other states we’ve covered—as well as test novel incentive structures whose eventual efficacy remains to be proven. 

Over the past half-decade, Massachusetts has taken multiple steps to boost the role that rooftop solar, behind-the-meter batteries, electric vehicles, smart building energy controls and other distributed energy resources can play in reaching its clean energy goals. In fact, its approach may provide some lessons for other states that have a lot more DERs to handle. 

That’s the view of Chris Rauscher, director of policy and storage market strategy for U.S. residential solar leader Sunrun. The Bay State is “the tip of the spear when it comes to smart, distributed energy resource policy,” he said in an interview last week. “We’re now advocating in other parts of the country and out west in California for policies that we helped create in Massachusetts.” 

These include policies like the state’s Clean Peak standard, geared to incentivize DERs that can support peak grid demand reduction, and the Connected Solutions programs which offer lucrative utility incentives to behind-the-meter resources that can offer similar day-to-day grid flexibility. 

One noteworthy aspect of these programs is that they’re being rolled out despite the fact that Massachusetts investor-owned utilities Eversource, National Grid and Unitil haven’t yet deployed smart meters that can measure their real-time impacts, he said. That’s possible because they’re implemented under energy efficiency constructs, rather than more complex demand-response mechanisms that have dogged DER participation in California’s markets

Electric vehicles are also testing the opportunities to serve as grid resources, from National Grid’s infrastructure build-out for 1,200 Level 2 and 80 DC fast-charging stations, Eversource’s pilot program enlisting home EV chargers to combat peak loads, and a novel program to tap electric school bus batteries as vehicle-to-grid assets.  

At transmission-grid scale, ISO New England is among the country’s first grid operators to open wholesale energy markets to aggregated energy storage as mandated by the Federal Energy Regulatory Commission’s Order 841. Sunrun is just one of the storage vendors tapping this new opportunity to pull together batteries to bid into ISO-NE capacity markets. 

This could lay the groundwork for ISO-NE to expand similarly lucrative opportunities to broader DER participation under FERC Order 2222 — even as it faces challenges from state and regional political leaders to what are seen as renewables-unfriendly aspects of its broader approaches to maintaining grid reliability. 

State support to boost solar and the resulting challenges 

Massachusetts isn’t the sunniest state, but it has jumped in solar state-by-state rankings to reach eighth place this year, with 2.85 gigawatts installed as of mid-2020, according to Solar Energy Industries Association data. On the distributed side, that growth has been boosted both by retail net metering and the state allowing customers to earn solar renewable energy certificates for the kilowatts they produce. 

On the larger-scale distributed solar front, the Solar Massachusetts Renewable Target (SMART) program has incentivized gigawatts' worth of development, giving solar-storage projects rights over the wholesale capacity value of their batteries. The program hasn’t come without problems, however. A rush of applications after its 2018 opening led to backlogs, and utility interconnection studies have delayed many projects and imposed high upgrade costs on others. 

The state’s Department of Energy Resources moved last year to double the SMART program capacity from 1.6 gigawatts to 3.2 gigawatts, opening up more opportunities. But it also added new restrictions on what types of land can host solar development in an effort to protect sensitive habitat and incentivize brownfield or rooftop projects. Solar groups argue the restrictions have placed the most economical developments out of reach. 

Meanwhile, Massachusetts faces similar interconnection problems as many states growing their solar capacity. Proposed reforms at the state Department of Public Utilities (DPU) could clear one roadblock by mandating that multiple projects are processed for interconnection as a “cluster,” rather than one at a time, which would reduce backlogs in Eversource’s queue, said Ilan Gutherz, vice president of policy and strategy for developer Borrego Solar. 

“The other major interconnection issue has been around cost,” he said. “In the last year or so, the level of distributed generation resources that have been proposed have started to get the transmission planners at ISO New England and the utilities’ transmission arms worried” that new solar may cause grid disruptions.

A series of Affected System Operator studies are underway to address this uncertainty. The first to be completed by National Grid shows grid upgrade costs that may break the economics of proposed solar projects, he said. 

Whether developers, utilities and ISO-NE can agree on methods to reduce the need for those grid upgrades — such as managing solar output to avoid overloads during peak hours — remains to be seen. The DPU recently opened a proceeding to consider alternative cost allocation frameworks for the grid upgrade costs the industry could face in the coming years.

Connected Solutions: A novel approach to behind-the-meter flexibility

As solar grows, it floods the grid with ample midday power, then fades away during rising afternoon and evening demand peaks. Those peaks drive high marginal electricity costs and carbon emissions for Massachusetts and New England, and in solar-rich states like California and Arizona have emerged as “duck curve” supply-demand imbalances that other states are trying to mitigate.  

Massachusetts’ Connected Solutions program seeks to tap DERs to help solve these peak demand challenges. Over the past three years, National Grid and Eversource, which collectively serve about 2.7 million electric customers in the state, have expanded from pilot projects to full-blown programs, serving tens of thousands of customers. 

Connected Solutions has found some elegant workarounds to problems other states have encountered in enlisting behind-the-meter batteries and grid-responsive loads as peak-reduction assets, according to Chris Ashley, VP of utility sales for DER management system provider EnergyHub, which operates National Grid’s residential and commercial-industrial program and Eversource’s residential program.

First, it offers lucrative incentives, not just for installing equipment like smart thermostats or behind-the-meter batteries but also for the kilowatts of load reduction they’re able to deliver over the year during a predetermined set of days, he said. 

Those incentives add up to $200 per kilowatt for commercial customers and $275 per kW for residential customers. Thermostats can lower household consumption by an average of 0.75 to 1 kW, and batteries can provide about 4 to 5 kW of grid support, meaning hundreds of dollars for thermostat participants and thousands of dollars for battery owners. 

Battery installers can rely on those incentives to lower upfront costs for customers, creating the economic incentives to grow both asset classes quickly in National Grid and Eversource territory, with more than 35,000 thermostats and more than 1,000 batteries across both utilities, Ashley added. 

That adds up to about 25 to 30 megawatts of peak load reduction from thermostats and close to 5 megawatts from batteries, he said. Importantly, unlike California’s demand response regimes, Connected Solutions allows batteries to discharge to the grid, which is critical to boosting their value, he said. 

“The first year of the battery program, the only value the utility could capture was shifting net load to the customer,” which yielded less than 1 kW per home, he said. Utilities and regulators were able to quickly agree to allow battery grid export, largely because the decision wasn’t made in the context of traditional demand response programs, which have strict and complex processes to align the market rules of grid operators and utilities. 

Instead, the Connected Solutions program is part of state-regulated energy efficiency programs, which require only that utilities pursue programs whose benefits can be proven to outweigh their costs. “The regulatory constructs here are based on a cost-effectiveness test,” said Michael Goldman, Eversource’s energy efficiency director of regulatory strategy and planning. 

Connected Solutions’ approach of paying for performance after the fact, rather than distributing incentives upfront, helps ensure that the benefits outweigh the costs, he noted. It also extends to many different technologies, unlike utility programs focused only on batteries, or smart thermostats, or electric vehicles, according to Goldman. 

Eversource is in the midst of a pilot program that gives the utility some control of when customers charge their EVs in exchange for Connected Solutions incentives — an important way to manage a load that can draw as much grid power as the entire home it’s connected to, he said. Those pilots are set to continue for a while; regulators rejected National Grid's larger-scale, $166 million EV infrastructure investment plan last year to await more results from its ongoing pilots, although they did approve the utility's plan to test residential off-peak charging incentives. 

Clean Peak standard: Pricing performance to grid needs 

This technology-agnostic approach also underlies one of Massachusetts’ novel contributions to state clean energy-grid support policy, its Clean Peak Program. First proposed in 2018 and officially launched this year, Clean Peak incentivizes resources that can match their operations to grid needs, largely by paying credits to resources that can provide power during hours of peak demand. 

This “allows a company like Sunrun to batch together your solar system, your battery, maybe an EV or heat pumps, and provide all of those as a peaking resource” — at least in principle, Rauscher said. “It has only just gone live in the last few months, and in this crazy COVID year, it remains to be seen how much enrollment...[and] performance we’re going to see,” he said. “I think that in 2021, especially during the summer, is when we’ll see it really take off.” 

Clean Peak has faced criticism for its potential gaps in driving marginal emissions reductions. To reduce complexity, the program provides four-hour windows that align with typical peaks. Real-world wholesale market price spikes could well be a better referent for when resources are most valuable, and a carbon price could be an even more effective incentive, according to research from Columbia University, New York University School of Law and WattTime, the grid-emissions-tracking nonprofit. 

It’s also possible that Clean Peak incentives may miss their target of energy storage systems that need incentives and end up boosting returns for projects that would have penciled out economically without them. 

Borrego Solar’s Gutherz calls those “anyway” resources, meaning “resources that were going to be built anyway,” such as solar-storage projects that already have access to the SMART program's solar and storage incentives or offshore wind farms that will be financed and built based on state-mandated long-term contracts, and that will generate clean peak credits more or less by accident. “All it’s really doing is giving those project owners a cushier return.” 

At the same time, otherwise unsupported resources that might rely on Clean Peak to pencil out economically may find the program’s incentive structure problematic for would-be financiers, he said. That’s because it’s designed in a way that could drive credit prices far below their starting value if the supply of peaking resources exceeds predicted levels, he said. 

Whether or not these problems stymie development may depend on the nature of the long-term contracts for Clean Peak-earning resources under development by utilities. Right now, solar developers like Borrego are waiting for those plans to emerge, he said. 

Tapping DERs without smart meters and building the foundations of a distributed grid

Advanced metering infrastructure is often a prerequisite for obtaining the 15-minute interval data needed to track and credit real-time behind-the-meter contributions to grid services. But Massachusetts’ advanced metering infrastructure rollouts have been put on hold pending a regulatory review of their costs and benefits, even as utilities have proceeded with broader grid modernization investments that will support DER integration.

To measure the value of their Connected Solutions programs, National Grid and Eversource have been able to work around their lack of smart meters today by taking another liberty not available in all markets: measuring the DERs themselves.   

Advanced metering infrastructure “is helpful and it adds value, but it’s not necessary,” Goldman said. “That’s because we have this proliferation of connected and communicating devices” and regulator approval to pull the data from those connected thermostats and inverters to determine the incentives they’ve earned — with an independent third-party verification of the average value of dispatched savings to true up those readings.

At the same time, Massachusetts’ utilities are under a long-standing Department of Public Utilities order to ensure their grid modernization investments are tied to delivering customer benefits. That includes a recently opened DPU investigation into how utilities manage DERs into their grid plans, which could address interconnection bottlenecks and drive a more forward-looking approach to DER-grid integration, much as several ongoing proceedings in California are seeking to do.

ISO New England and the wholesale-retail connection 

ISO-NE has taken a lead among the country’s grid operators in opening its markets to aggregated energy storage under FERC Order 841. That’s ushered in a flood of new business models in Massachusetts, from Sunrun’s 20-megawatt virtual power plant to Engie’s offer to take on dispatch rights for storage systems it designs for third parties. 

One critical reason for the boom is that, unlike California grid operator CAISO’s approach to DER aggregations, ISO-NE’s rules free market participants to participate in state programs as well, Sunrun’s Rauscher said. That includes allowing solar-storage systems to earn solar net metering credits while bidding batteries into its capacity markets, without also committing the batteries to the vagaries of its energy markets, he said. 

That’s what allows Highland Electric Transportation, the company planning to aggregate electric school bus batteries in Beverly, Mass., the freedom to build a revenue model that can include Connected Solutions revenue with participation in the ISO’s emergency response program, CEO Duncan McIntyre said. 

ISO-NE also allows participating resources to “meter at the inverter, not the utility meter,” Rauscher noted, which would otherwise bar Massachusetts customers lacking smart meters from participating. That also credits batteries for discharging to the grid, which again, CAISO doesn’t yet allow. 

All in all, “they’ve been a leader on integrating direct bids from DER aggregations,” he said. At the same time, ISO-NE is facing pressure from New England state governors and U.S. senators including Bernie Sanders and Elizabeth Warren to change its approach to securing resources to keep the grid reliable during summer heat waves and winter cold snaps. 

Critics say those market reforms have undermined state carbon-reduction policies by slashing the value of clean energy alternatives against fossil-fueled generators. It’s unclear how these conflicts will affect DER policies, but they’re likely to play an important role in other states as well. 

New York state grid operator NYISO and mid-Atlantic grid operator PJM are facing similar pressures under FERC orders that critics say have disadvantaged state-supported clean energy resources. But in terms of bringing the conflict between state political leaders and FERC-regulated grid operators to a head, “ISO New England is kind of ground zero in the country on that.”