In solar policy, Massachusetts seems to have taken up a familiar aphorism: “The difficult we do right away, the impossible takes a little longer.”

Lawmakers, weary of fights to protect the existing net energy metering (NEM) and solar renewable energy credit (SREC) incentives, passed Chapter 75 of the Acts of 2016. The bill ordered the “immediate” implementation of a successor tariff. The new policy must support “a stable and equitable solar market at a reasonable cost to ratepayers.”

The Massachusetts Department of Energy Resources (DOER) and distributed energy resources (DER) stakeholders are working to meet the Act’s dictates. But reconciling the competing interests is likely to require distributed solar policies as-of-yet untested in the United States.  

At least three crucial questions, still unresolved in solar policy debates across the country, must be answered by the new policy. One is how to calculate a perceived cost shift. Another is how to value solar generation sent to the grid. The third is how to equitably distribute credits for a solar array’s output to offsite subscribers.

The DOER’s research has already led it to one conclusion:

“Three consecutive analyses conducted by DOER comparing SRECs to other policy alternative structures have shown tariffs to be significantly less costly to implement,” DOER reported when it unveiled its “Next Generation Incentive Straw Proposal” in September.

The existing policies “have successfully increased solar deployment” but they have created “market risk and uncertainty” that has led to “higher incentives than necessary,” DOER added. “Programs can be improved to better control ratepayer costs, while continuing to expand solar deployment.”

The DOER’s leading objective for its successor tariff is to maintain “robust growth” for each solar sector, while also moving away from fights over retail rate NEM. The Department also wants to ensure there are adequate incentives to expand access to solar through community shared solar and programs for low-income electricity consumers.

DOER described three further objectives of the stakeholder-driven process. One is providing incentives for the co-location of solar and energy storage. A second is to formulate accepted solar project siting guidelines. And, finally, DOER wants to expand ownership of solar by residential and business electricity customers.

DOER’s 'straw proposal'

The DOER’s proposed tariff would replace the NEM retail rate remuneration and the SREC value that currently go to solar owners for the generation their arrays send to the grid, said Acadia Center Massachusetts Office Director Peter Shattuck, who’s followed the proposal.

The new tariff would apply to Massachusetts’ next 1,600 MW of installed solar capacity.

A tariff of approximately $0.30/kWh would go to owners of the first 200 MW to qualify for interconnection under the new policy. In this declining block incentive program, owners of the next 200 MW to qualify would receive a tariff 5% lower. The value would continue to decline with each successive 200 MW block.

The tariff is called "net of energy value" because it is designed to deliver a credit that values a consumer’s solar generation minus the value of energy she gets from the grid.

A monthly minimum reliability contribution (MMRC) charge is also required by the Chapter 75 legislation. The MMRC “shall ensure that all distribution company customers contribute to the fixed costs of ensuring the reliability, proper maintenance and safety of the electric distribution system,” according to the law.

Owners of solar installations with features that meet designated program objectives would end up with a higher than “net energy value,” through “adders” that could apply.

Adders would go to owners of solar in preferential locations such as such as on landfills and brownfield, on solar canopies, and on other buildings. They would go to preferred off-takers such as those who build solar on low income properties and those who subscribe to community shared solar.

Adders would also go to solar that includes features supported by state policy such as solar paired with behind-the-meter energy storage and non-net metered solar.

The tariff rate for each block would be a fixed return for 10 years to 15 years and would apply to all Massachusetts electric distribution utilities. Such generators may be net metered, participants in the ISO-New England electricity markets, or qualifying facilities (QFs) as defined by the Public Utility Regulatory Policy Act (PURPA).

The 200 MW of nameplate capacity in each block would be divided by load share. Approximately 100 MW would go to customers in the Eversource territory, 95 MW to National Grid customers, and 5 MW to Unitil customers.

The utilities would be allowed full cost recovery through a fixed, non-bypassable monthly charge for all tariff payments and administrative costs.

Each 200 MW block would have projects in five categories. There would be standard less-than-25 kW projects and less-than-25 kW projects for low income customers. There would be mid-sized projects of between 25 kw and 250 kW and of between 250 kW and 1 MW. And there would be a large project size of between 1 MW and 5 MW.

Implementation would begin after the DOER rulemaking and completed by a DPU stakeholder proceeding. The final tariff would have to establish a procedure for allocating payments to owners of the renewable generation and a mechanism through which the distribution utilities would recover the costs of program implementation and operation.

First responders to the DOER proposal

As in other states, utilities have serious concerns about the cost of solar incentives.

“The DOER recognizes that the prices paid to subsidize solar development through previous programs were high and did not factor in the reduction in overall costs of development,” National Grid Spokesperson Amie O’Hearn told Utility Dive. “We look forward to seeing further reductions in subsidies.”

Eversource Massachusetts Media Relations Manager Michael Durand agreed. “The cost impact to our customers of solar incentives in Massachusetts compared with other states remains a top priority for us,” he told Utility Dive.

Controlling costs is the paramount benefit utilities hope to obtain with the new tariff. But the DPU and other stakeholders see a wider range of benefits. Among them are long-term revenue certainty for solar builders and solar owners, precise and predictable incentives, and better synergies between existing and new policies.

Renewables advocates emphasize those DOER targets in comments on the proposal.

If the new tariff includes flexibility and a provision to be extended, it can offer more certainty to the solar market than the existing policy and can be “a smooth glide path to long-term cost-competitiveness,” according to a filing by the Northeast Clean Energy Council.

“The most important thing is continuing solar development,” agreed Acadia’s Shattuck. “That can best be accomplished by a value-based payment structure that accurately credits solar generation.”

The value of solar’s benefits, including energy, capacity, and price and emissions reduction, can be worth more to the system than the retail price of electricity, Shattuck added. “We haven’t seen universal interest yet in an open transparent process to determine the accurate value of solar.”

Acadia Center Attorney Mark Lebel sees opportunity in the DOER straw proposal if stakeholder differences can be resolved. “There are a lot of important details still to be worked out but if it lowers costs for ratepayers and still provides the certainty developers need for financing we could get a win-win solution.”

The utility critique

A “Joint Distribution Company” comment represents the Eversource, National Grid, and Unitil response to the DOER proposal. It anticipates a tariff to be filed with DPU in “early 2017,” a DPU rulemaking “by spring 2017” and a final DPU approval “by summer 2017.”

The companies support DOER’s effort to comply with the legislation, but find the “administratively determined compensation levels” to be “a significant concern” because market-based incentives could “further lower costs for ratepayers.”

Incentive prices for projects in the 250 kW and larger categories should “competitively set…to avoid over-compensating such projects for their output.”

With solar costs trending downward, “development costs could continue to shrink, automatically resulting in the provision of more compensation than necessary,” the filing argues. “Introducing competition into the program will help capture those cost savings for customers.”

Competitive bidding is required in most utility, corporate, and government procurements because it leads to lower prices, the filing adds.

Among other “specific concerns,” the filing argues the proposal’s “administrative complexity” will lead to high administrative costs.

The utilities say the tariff and adder prices to be set for each of the declining blocks constitute a “disconnect” from the Chapter 75 requirement to share costs equally among ratepayers. They also find the tariff and adder prices higher than other states’ incentives.  

“National Grid’s program in Rhode Island and Eversource’s program in Connecticut are proof that solar generating facilities can be and already are being built for less money,” the utilities argue.

The current Massachusetts policy returns 185% of the installed cost of a 3.9 kW customer-owned facility and 182% of a 6 kW customer-owned facility, according to recent Consumer Energy Alliance (CEA) research.

Using the same methodology, CEA reports in its filing that residential rooftop solar systems would receive “incentive rates in a range from 199% of the installed system costs, if the system receives both net energy metering and [Next Generation tariff] incentives, to 141% of the installed system costs, if the system only receives the NextGen incentives.”

“The cost shift onto traditional customers is still considerable,” CEA’s filing adds.

The utilities also argue that as their portions of each block fill at different paces, developers could move between them, creating “marketplace confusion and unequal ratepayer costs.” Remedies for this should be built into the timing and pace at which successive blocks open.

The utilities find the straw proposal to be unclear on allocation of the rights of renewables projects’ capacity products, which could have significant value. The filing argues rights to the capacity products should be transferred to the utilities or reduced.

Finally, the joint filing argues the proposal raises cost recovery issues DOER should leave to the DPU.

Chapter 75’s intent was to spur another 1,600 MW of solar growth “at a lower cost to electricity customers,” the utilities argue. The new policy’s “highest priority” should be to reduce the price of the incentives. Doing so, they add, will promote “the orderly transition to a stable and self-sustaining solar market at a reasonable cost to ratepayers.”

Other stakeholder responses

While the DOER proposal clearly aims to expand solar at a reduced cost, there are “a few important provisions open to interpretation,” according to CEA Counsel James Voyles. “Most notably, the proposal implies that net metering at the retail rate will be displaced in favor of the new proposed terms, but the proposal is not explicit in saying that.”

Acadia’s Shattuck said “it would help address some of the fits and starts caused by the net metering caps if they can pull it off, but there are implementation questions.”

Chapter 75 requires that “the costs of the program are shared collectively among all ratepayers of the distribution companies,” Shattuck pointed out. “That would theoretically be taken care of by the MMRC but the MMRC is far from a settled question.”

Acadia’s LeBel is participating in a ongoing DPU-led proceeding intended to define and calculate the MMRC.

“It is not a regulatory concept that’s ever been defined before in Massachusetts or any other state,” he told Utility Dive.

Renewables advocates are concerned the MMRC could become a tool in the growing national effort to impose fixed charges on solar owners.

“Some stakeholders are thinking of it as a minimum bill but the utilities think of it in a broader way that could include any number of fees on distributed generation customers,” LeBel said.

It is a catch-22 in the NextGen incentive process because its value will almost certainly not be finalized before the tariff, he added. “But eventually there will be an MMRC of some kind.”

That could create complications for the new program if it is applied retroactively. Solar owners buying into the first 200 MW block could then find their remuneration reduced more than they anticipated, LeBel said. A fix for that would be applying the MMRC to the NEM credit because that reduction would be balanced by an increase in the tariff rate.

“It could still go a lot of different ways,” he observed.

The filing from the Energy Freedom Coalition of America (EFCA), which is funded by SolarCity and other leading national DER vendors, proposes an improved SREC-based program instead of a completely new policy.

A new program that is fundamentally different from the existing policy could increase “inefficiencies and transaction costs” and “yield unknown results,” EFCA argues. DOER should instead ratchet down the value of SRECs under a slower timeframe.

In addition, DOER should attribute “locational value” to solar, EFCA argues. It should also add value to the NextGen tariff for “PV system benefits that are not already taken into account” such as “environmental benefits, energy demand reduction, and other costs that are avoided.”

The DOER straw proposal was based in part on a research report commissioned by DOER from Sustainable Energy Advantage (SEA).

The declining block compensation creates stability and predictability important to businesses, SEA Director Tom Michelman told Utility Dive. “There are critiques suggesting the step downs are too fast and not fast enough, and critiques saying the block sizes should be bigger and smaller, but in general it is a good structure.”

One concern is that the DOER proposal does not allow for adjusting the compensation levels depending on how fast the blocks are filling, Michelman pointed out. “That was done in California but not in New York and New York has blocks that are stuck and there is no way under the current rules to unstick them.”

It could be an important factor if an unexpected market change, perhaps the imposition of an import tariff, causes spiking costs that suddenly limit solar’s financial feasibility, he explained. “There is no dynamic adjustment to increase the tariff if necessary, only an adjustment to decrease it.”

The role of the state’s Municipal Light Plants (MLPs), which account for 15% to 18% of the energy consumed in Massachusetts, remains undetermined, Michelman said. Because they were exempted from paying for SREC credits under the existing policy, “this is likely to be more expensive for them.”

The Massachusetts Municipal Wholesale Electric Company (MMWEC), which represents MLPs, “is working with the DOER and other MLPs on a solar incentive program,” MMWEC Director of Communications David Tuohey told Utility Dive. It will “reflect the local decisionmaking authority of municipal utilities while supporting the state’s solar energy goals but details are still under development.”

Community solar questions

Finally, Michelman said, it will be “very important” if there is, in the straw proposal, a way to move away from NEM but maintain a bill credit “that can be assigned.” Such a mechanism is, he explained, “a significant business lubricant for making community shared solar projects work.”

Massachusetts electricity customers strongly favor solar and face the high electricity prices that can sustain its value proposition. But the state does not have the solar resource or available land to support significant utility-scale solar growth. And a large proportion of residents lack solar-suitable rooftops. Community solar is expected, therefore, to be a key growth driver.

Community solar “does not easily work without the bill credits that were part of net metering,” Michelman said.

Taking NEM out of the equation does take some controversy out of the equation, he acknowledged. “The utilities, for good reason, do not like the way net metering is structured, both in the level and in the way they get compensated,” he said. “They reportedly much prefer what they see as this cleaner tariff approach.”

The way the debate is unfolding, it appears the program will include “the ability to assign credits to a third party or a subscriber without net metering,” Michelman said. “If DOER and the stakeholders can make that happen, it will be a great success.”

Acadia’s LeBel elaborated. “They want to set up a virtual net metering structure without using virtual net metering.”

The basic idea is to use the concept of QFs under PURPA. “It would be a new system for allocating payments to QFs like net metering credits,” LeBel said. “That is another unprecedented thing. As far as I am aware, nobody has done that across the country and it is not clear it is legal. There are a lot of other policy details around how to make it work."