In the battle between utilities and clean energy advocates over cost shifting, Massachusetts regulators have handed the clean energy side a victory.
In a decision issued last week, the state’s Department of Public Utilities denied utility National Grid’s proposals to impose new access fees to community solar projects, add new tiered rate structures on residential and small business customers, and make changes to demand charges for large commercial and industrial customers.
The ruling, which applies to Massachusetts Electric Co. and Nantucket Electric Co. — two companies owned by National Grid that filed a general rate case last year — rejected the argument that distributed generation such as wind and solar power shifts costs to other customers. That’s a common argument from utilities seeking to change rate structures and impose new charges on distributed energy systems.
The fundamental concept is that volumetric charges — the cents per kilowatt-hour that customers pay for electricity — make up for the majority of the fixed costs of maintaining the grid. Under the net metering regimes in place in 41 states, however, distributed generation systems reduce their kilowatt-hour charges, potentially shifting the burden of covering fixed costs on to customers that aren’t generating their own power and offsetting their consumption.
But pro-solar groups including the Acadia Center, Vote Solar and the Energy Freedom Coalition of America (EFCA) protested that National Grid had failed to provide data or evidence to back up this assertion. DPU’s ruling sided with these protests, finding that National Grid “has not quantified the amount of costs attributable specifically to DG customers and has not quantified the distribution system benefits associated with DG customers in its service territory.”
“The Department is not persuaded that a cost-shift from DG customers to non-DG customers, in fact, exists,” wrote regulators.
That finding was welcomed by Nathan Phelps, Vote Solar’s program manager of DG regulatory policy. “National Grid argued that there was a theoretical cost shift, but they did not provide any evidence,” he said in an email. “Such unsubstantiated assertions are not helpful, and certainly are not grounds for rate changes.”
DPU used this assertion as the basis to deny several parts of National Grid’s proposal, and order the utility to redo the rest of its rate case calculations without them.
Regulators rejected National Grid's proposal to impose access fees on solar or wind power projects for municipalities and low-income customers that operate under the state’s virtual net metering regulations. National Grid justified the fee by saying such projects were using far fewer kilowatt-hours of power, and thus not paying their fair share of fixed costs.
But opponents like the nonprofit Acadia Center said that singling out those types of projects would “arbitrarily discourage key types of distributed generation, including community shared solar and projects that benefit affordable housing projects and low-income ratepayers.” In other words, it would hinder customers who can't put solar on their own rooftops.
Beyond that, the fees are “not based on an analysis of the costs and benefits of distributed generation to the electric system or even based on estimated costs to the distribution system,” the group wrote. Distributed energy backers have noted that these projects can actually help reduce system costs, by providing more energy closer to the point of consumption and reducing load on the grid.
The ruling could help bolster the business case for community solar in Massachusetts, which passed long-awaited net metering reform in April. As GTM Research solar analyst Austin Perea noted, this reform increased the state’s net metering cap to open up a backlog of commercial PV projects. But it also set in place a revised credit mechanism that will put new community solar and other virtual net metering projects at risk — a problem, considering that these types of projects are expected to make up a significant share of new solar projects in the state.
The DPU also rejected National Grid’s proposal to apply tiered fixed charges to residential and small business customers, under an unusual scheme that would charge them more depending on how much energy they use over a year. Under the proposed rates, these fixed charges could rise from $4 to about $20 per month for residential customers, and from $10 to about $30 per month for small commercial customers.
Many other states are reviewing similar proposals from utilities, with 25 states taking some sort of action on the issue in the second quarter of this year alone. Some, such as California and Arizona, have approved smaller fixed charge or minimum bill increases. But fixed charges have also seen considerable backlash from consumer advocates and green energy advocates, since they reduce the value of using energy more efficiently, as well as degrade the business case for rooftop solar.
The DPU’s decision found that National Grid’s proposed tiered fixed charges were problematic because they would accrue over the course of a year, making it hard for customers to manage them. For these reasons, it found that they provide “no incentive to lower demand and electricity use below the highest level within a tier,” and “distort incentives to conserve electricity, may unfairly impose higher costs on certain customers, and discourage customers from investing in cost-effective energy efficiency.”
Finally, DPU’s ruling denied National Grid’s “demand ratchet” proposal for large commercial and industrial (C&I) customers. Demand ratchets are more complicated ways to measure demand charges — fees based on the maximum amount of electricity a customer draws from the grid at any moment of time during a month.
Demand charges are a way to link customers’ electricity costs more closely with the fixed costs of supplying them with their peak power needs, and encourage them to control that peak consumption. Importantly, demand charges have been the driver for C&I customers to invest in load control equipment or energy storage to reduce peak power consumption. In fact, this business case is driving commercial behind-the-meter battery deployments in the U.S., according to GTM Research.
But demand ratchet policies can reduce the value of this kind of investment, by spreading or shifting the way that demand charges are assessed, according to Ravi Manghani, GTM Research’s director of energy storage. “Usually markets with very strong ratchet rules make energy storage for demand charge reduction less appealing,” he said.
DPU’s ruling found that National Grid’s demand ratchet proposal in particular would use the previous 11 months’ peak demand as part of its calculation, which “distorts the price signal to the customers and discourages customers from investing in load control equipment that would otherwise be cost-effective.”
The utility “failed to provide sufficient evidence to demonstrate that a customer would have any incentive to reduce their demand after it reaches its annual peak demand,” wrote DPU.
Massachusetts is exploring a state-wide energy storage mandate similar to the 1.3 gigawatt mandate that California set in 2014, albeit with smaller ambitions. Still, a recent study found that 600 megawatts of energy storage could save ratepayers $800 million in costs through 2025, giving state regulators reason to support policies that will help make batteries more economical, not less.
The state’s utilities are also in the midst of seeking DPU approval for major smart grid proposals, including large-scale smart meter and distribution automation investments.