Will the country's first mandatory residential demand charge slow the Massachusetts solar boom?
Opponents of the charge, approved as part of an Eversource rate case, say it could harm the growth of solar and other distributed resources by significantly increasing costs for customers.
Massachusetts regulators made history Jan. 5 by approving a three-part rate for Eversource Energy that includes a mandatory demand charge for residential customers who own distributed energy resources.
Eversource is the first regulated electric utility to win approval for such a charge from state regulators.
It is one of the best examples so far of new strategies being used by utilities to advance controversial rate concepts, such as demand charges.
A demand charge, which is common for commercial-industrial customers, imposes a significantly higher per-kWh charge for the kWh used during a customer’s highest 15 minutes of electricity consumption each month. For some commercial-industrial customers, it makes the cost for that 15-minute period as much as half their monthly bill.
Thanks to Massachusetts’ strong solar policies, it became the eighth biggest U.S. residential solar market by 2016, rising to sixth in Q3 2017, according to the most recent Solar Energy Industries Association figures.
But Eversource opponents say the demand charge could compromise the value proposition for distributed energy resources (DERs) like rooftop solar, and retard market growth, by causing the same bill increases for residential customers that it tends to cause for commercial-industrial customers.
For that and other reasons, the Eversource demand charge may soon bring the courts or the legislature into the debate.
Like Eversource, many utilities have asserted in recent rate cases that without new revenue to replace displaced distribution revenues, distribution system infrastructure and maintenance costs are shifted to non-DER-owning customers. But utility arguments for higher fixed charges to address this “cross-subsidy” have not convinced their commissions — until now.
Eversource asked the state’s Department of Public Utilities (DPU) for the new rate to recover growing “displaced distribution revenues.” Eversource’s traditional cost of service approach to ratemaking identified an $8 million per year revenue loss to DER owners.
In this second and concluding portion of its rate case (Docket 17-05), Eversource won DPU approval to adopt the monthly minimum reliability contribution (MMRC). Mandated by the state’s landmark 2016 Chapter 75 legislation, the MMRC will be used as a demand charge.
“There is a legitimate concern among regulators that everybody pays an equitable share for their grid use. But defining how that share is best measured and collected is highly controversial."
Senior Advisor, Regulatory Assistance Project
The Chapter 75 legislation introduced the MMRC to “ensure that all distribution company customers contribute to the fixed costs of ensuring the reliability, proper maintenance, and safety of the electric distribution system.”
An increased fixed charge and a reduced per-kWh charge are the other two parts of the new three-part rate, though they have caused none of the controversy stirred by the demand charge. The demand charge will apply only to residential customers who earn remuneration via net energy metering credits for the electricity their DER systems exports to Eversource’s distribution system.
Eversource used two emerging utility strategies to convince regulators to approve the rate. First, it worked through a pre-approved rate structure, in this case the MMRC. That gives regulators precedential cover.
Second, it allowed regulators to limit the impact of the potentially disruptive rate by separating DER owners within the residential customer class.
The ruling and the new rate
Eversource initially filed its rate case in January 2017. Last November, the DPU addressed part of it by approving a $36.4 million revenue increase, a performance-based ratemaking (PBR) mechanism, and funding for electric vehicle infrastructure and energy storage programs. DPU's Jan. 5, 2018 order completes the rate case by addressing rate design.
Eversource spokesperson Michael Durand emailed Utility Dive that “the demand charge portion of the MMRC will eliminate, to the extent possible, the unfair cross subsidization by non-net-metered customers that currently exists.”
Durand said the demand charge is needed so DER owners pay “their fair share of the cost of the significant maintenance and upgrade work we do on the local grid every day.” Non-DER owners are now “paying more than their share.”
The demand charge addresses the cross-subsidy because it “accounts for the peak amount of electricity needed by a customer in any given month regardless of how many kWh they consume,” he added.
But, he acknowledged, “peak demand is what we have to size our equipment to meet.” This would appear to confirm the idea that the demand charge is not directed at reducing system peak demand but at the cost shift.
Durand declined Utility Dive’s request to answer follow-up questions.
The DPU found Eversource had “demonstrated a cost shift” from “costs directly imposed by net metering facilities on the distribution system." Because of this, Eversource was justified in using the MMRC as a remedy, it concluded.
There were flaws in Eversource’s studies and cost calculations, but they met DPU standards sufficiently to justify the proposed rate design, the commission ruled. It rejected arguments that Eversource’s cost of service calculations violated rate design principles by omitting DER “long-run costs and benefits.”
The DPU accepted Eversource’s argument that its calculations were “far more granular” than those filed by intervenors. It also accepted the Eversource argument that “the issue of benefits confuses the issue of whether net metering customers are displacing their usage, thereby reducing the amount they pay to Eversource for the distribution service.”
And the DPU accepted Eversource’s argument that “any presumed benefits are long-run in nature and would not offset the companies’ short-run fixed costs.”
Inconsistent with efficiency and fairness
Environmental and DER advocates strongly objected to the new rate design. Acadia Center argued it is “inconsistent” with “rate design principles of efficiency and fairness.” The New England Clean Energy Center (NECEC) argued it will cause “arbitrary” and “extraordinary and unreasonable” bill impacts. Both Massachusetts’ Attorney General (AG) and Department of Energy Resources (DOER) concurred.
However, DPU concluded Act 75 allows approval of an MMRC that "equitably" allocates fixed costs, does not "excessively" burden ratepayers, does not "unreasonably inhibit" development of DER, and is intended to offset costs necessary to maintain the distribution system.
The Eversource proposal allows DER owners to continue getting net energy metering credits but adds a demand charge for their highest 15 minutes of usage in each billing period. The reduced per-kWh charge that is the second part of the three-part rate is intended to maintain “revenue neutrality,” the DPU decided. A utility-led “communications plan” will “educate residential customers” on how to manage their demand.
The rate design therefore meets legal and regulatory procedural and substantive requirements and standards of a “just and reasonable” rate, the DPU ruled.
The DPU acknowledged residential customers may have difficulty with demand charges without advanced metering infrastructure, which Massachusetts has not yet deployed.
Residential DER owners “are more sophisticated than the average residential customer” and they don’t need smart meters to manage their demand, the ruling said. They only need to learn how “to avoid the simultaneous use of electricity-intensive appliances.”
But because “a residential demand charge is a significant shift from current ratemaking,” Eversource must file “detailed educational plans, customer outreach, and tools by June 1, 2018,” the DPU ordered.
No good alternatives
None of the intervenors “presented a feasible alternative MMRC proposal with supporting evidence,” the DPU concluded. “Implementation of an MMRC reduces the effects of the cost shift” and will not “excessively burden ratepayers with an MMRC or ratepayers without an MMRC” or “unreasonably inhibit” DER growth, it found.
Acadia Center Attorney Mark Lebel told Utility Dive the approval of the non-coincident demand charge and the separate rate for DER owners was unexpected because they were unprecedented. “Most students of rate design generally tend to find those two things not the best kind of ratemaking.”
A non-coincident demand charge applies a per-kW charge for the customer's highest 15 minutes of usage, whether that 15 minutes coincides or does not coincide with the system peak demand. It is considered poor ratemaking because the customer's reduced usage, in response to the price signal, does nothing to reduce the system's peak like it would if the demand charge coincided with the system's peak.
“Acadia Center proposed a distribution reliability charge that could be implemented more gradually with current metering,” LeBel said. “It would be a variation on a three-part rate where the third part, instead of a demand charge, would be a rolling 12-month average of kWh consumption.”
It deals with Eversource’s displaced distribution revenues by not counting months “in which exported generation exceeded imported electricity,” he added. “It addresses the cost shift as effectively as this non-coincident demand charge. A coincident demand charge should be on the table when we have the right advanced metering technology and customer education,” he said.
The argument by Eversource and the commission that DER owners will figure out how to avoid running major appliances at the same time is harder than it sounds, he added. And the DPU order on customer education highlights "how unprepared Massachusetts residential customers are for the complications of a demand charge."
Good and bad demand charges
The Acadia Center, along with NECEC, Vote Solar and others argued in their filings that a customer’s non-coincident peak “fails to track the peak demand that drives system costs.” The result is that “customers whose demand peaks outside of system peak periods would pay too much, and customers whose individual peaks coincide with system peaks may pay too little."
Regulatory Assistance Project Senior Advisor and rate design authority Jim Lazar agreed. “Non-coincident demand charges have the effect of overcharging customers with intermittent demand and undercharging customers with constant demand.” This is in part because reduced volumetric rates are imposed with demand charges to keep overall revenues neutral.
“There is a legitimate concern among regulators that everybody pays an equitable share for their grid use,” Lazar said. “But defining how that share is best measured and collected is highly controversial. One of the few things that almost all rate design experts agree on is that the non-coincident demand charge is a bad idea.”
The more effective tool would be a coincident peak demand charge because it is “a rough proxy” for a time-of-use (TOU) rate, Lazar said. Both are “strong incentives to shift use to the off-peak hours."
"...there's nothing like a really bad proposal to unite stakeholders around a remedy.”
Attorney, Acadia Center
Strategen Consulting Vice President Lon Huber went further. The Eversource rate “is clearly designed to recover costs from solar owners.” But current thinking is that “the better residential rate design is TOU rates and coincident demand charges,” he said. “A non-coincident demand charge and a flat rate like this buck the trend.”
Other states are realizing that the best utility cost recovery comes through rates that send smart price signals, Huber added. “They can help integrate renewables and help address peak demand by recovering fixed costs in a way that has additional system benefits. This Eversource rate is just cost recovery.”
He cited the section of the ruling in which the DPU acknowledges that the non-coincident demand charge is a weak price signal. “They argue that ‘no intervenor demonstrated an alternative method that better measures cost drivers,’” he said. “Who admits the rate design it is approving is inferior?”
Eversource is moving ahead with implementation. To meet the DPU order, it must file its customer education plan by June 1. To comply with Act 75, the rates must be in place by Dec. 31.
But the DPU ruling does not say the customer education program must be executed ahead of the rate implementation, LeBel noted.
DPU rulings are often appealed to the Massachusetts Supreme Judicial Court (SJC) and the attorney general, who acts as a ratepayer advocate, is already contesting parts of the November decision, he added. “You could reasonably expect an appeal of the rate design at the SJC and a judgment before the end of the year.”
Addressing the DPU ruling will also likely “rise to the shortlist of priorities for clean energy advocates at the state legislature," LeBel said. Eversource is politically influential, but “the message that this is a threatening precedent will resonate with a lot of Massachusetts legislators.”
The legislature could enact a prohibition on demand charges for residential customers, he suggested. Lawmakers could also provide more specific guidance about the MMRC that prevents using it in this way.
“The problem is the legislature didn't define MMRC and there is no pre-existing policy definition, which gave discretion to the DPU, which it used,” Lebel said. “This is an opportunity to clean all that up and there's nothing like a really bad proposal to unite stakeholders around a remedy.”