A familiar fight between utilities and the solar sector is shaping up in New Hampshire.

Like many states, New Hampshire regulators are trying to devise a replacement incentive for retail rate net metering as part of a proceeding directed by state lawmakers last year when they lifted the cap on distributed generation. Filings in Docket 16-576 show the state’s debate will cover many of the known successor tariff possibilities and at least one brand new one.

The objective is “a net metering successor tariff for customers who both consume and generate electricity,” Donald Kreis, head of the New Hampshire Office of the Consumer Advocate (OCA) told Utility Dive.

The proceeding could be a path forward for a “sustainable rate design,” and a way to cut down on distributed generation customers shifting costs to non-DG ratepayers, according to Richard Labrecque, Eversource’s Manager for distributed generation.

Customers would be able to invest in distributed generation, but net metered customers would help recover the delivery system’s operating costs so they do not shift grid costs on non-net metered customers, he said. On the other hand, solar advocates want regulators to tackle a full cost-benefit analysis.

“The utilities are not acknowledging any benefits for reducing the need for transmission, distribution, and ancillary services,” said Kate Epsen, executive director for the New Hampshire Sustainable Energy Association (NHSEA). Additional filings from national solar groups underscore NHSEA’s push.

Both sides are trying to avoid the rancor that has characterized solar compensation debates in other states. In particular, the OCA “would like to see a negotiated resolution rather than litigating to the end because we don’t want this to be the next Arizona or Maine,” Kreis said.

Independent input, innovative ideas

Several noteworthy compensation options could, if successful, transform how other regulators look at successor tariffs. One proposal from former New Hampshire commissioner Clifton Below, who represents the City of Lebanon's City Council and sits on the town's Energy Advisory Committee, outlined a pilot project to test real time pricing (RTP) net energy metering.

The original statute authorizing net metering recognized the retail rate credit as "a rough justice for early adopters,” Below argued. “We are past the early adopter stage…[and] need a net metering policy that results in a more refined and granular justice for all involved.”

Instead, a successor tariff must fit the legislature’s goals of developing competitive markets for distributed generation, reduce costs across the board and give “reasonable opportunities” to own and operate distributed generation “while ensuring fairness in the allocation of costs and benefits,” he added.

Under the proposal, an optional real-time pricing net metering would enable customers to respond to "temporal price signals in supply markets" and “yield the needed stable utility revenues, reflect cost causation, and fairly apportion costs among customer classes,” Below argued.

“During each RT interval when power is exported to the distribution grid it would receive credit at NH load zone Real Time Locational Marginal Prices (RTLMPs) plus all generation related ancillary services that are also billed with LMPs (and hence avoided when the load at the wholesale meter point is turned down from what it would otherwise be), adjusted for avoided line losses,” Below wrote in his filing.

“Whenever power is imported from the grid it would be charged at the same real-time prices (RTPs) plus a mark-up to cover related billing and overhead (but not hedging services),” he added. The plan would also account for forward capacity market revenues, transmission and distribution system costs.

While a lack of advanced metering infrastructure could hurt the project, a 20-year pilot "work-around of existing utility metering and billing limitations” could be put in place by Liberty Utilities and the City of Lebanon to test its effectiveness.

TOU net metering

Another proposal is a familiar one for anyone well-versed in the Maine and Arizona proceedings over solar rates.

With the help of Strategen Consulting’s Lon Huber, the OCA introduced a three-part tariff is designed to end the traditional net metering structure. If successful, the proposal would allow New Hampshire to source 2.7% of its electricity from distributed solar and reduce costs to ratepayers to the tune of $300 million.

The proposal is divided into three options: a Time-Of-Use rate option for net metering customers, a new Fixed Solar Credit Rate for residential and commercial customers and a community solar program. According to Huber, the TOU and Fixed Solar Credit rate options would give long-term certainty for distributed solar users. All three would grow the state’s DG penetration beyond the 100 MW net metering cap and incentivize investment in new technologies.

Distributed generation owners could choose either the TOU or the fixed credit option to replace net metering, Huber said, with “the first [being] basically NEM with a TOU rate.”

“Customers who choose the TOU option can expect to pay a higher price, but also obtain a higher price, for power produced during the times of day when the grid is most stressed – 2 p.m. to 8 p.m.," the consumer advocate wrote in a statement.

As part of the TOU rate option, New Hampshire’s current $0.17/kWh average electricity price would be replaced by an on-peak $0.29/kWh price for electricity between 2pm and 8pm and an off-peak price of $0.10/kWh, he said.

The TOU rate also includes an hourly export charge. “We calculated the cost of using the secondary distribution system and charge for it,” Huber said. “If you have DG, you should pay for the part of the distribution system you use.”

The calculated export charge of about $0.04/kWh covers the use of about half the distribution system, he said. During the peak 2 p.m. to 8 p.m. period, distributed generation owners would get a total credit for export of $0.29/kWh, minus the $0.04/kWh export charge, and earn about $0.25/kWh. During off-peak hours, the calculation would be $0.10, minus $0.04/kWh, for a net $0.06/kWh credit.

This price signal could also spur deployment of battery storage and other peak demand technologies, Huber said. “It is meant to be technology agnostic and not punitive against solar.”

Under the Fixed Solar Credit Rate scheme, residential and commercial customers can lock in a bill credit for distributed energy production for 20 years. But the bill credit, which will initially start at the full retail rate credit ($0.17/kWh), will eventually step down in tranches to reflect fluctuating market prices.

The option will be capped at a total of 200 MW, with 75 MW set aside for small-scale distributed generation systems (proposed at 100 kW or less) and the rest for larger systems, according to the filing.

The cost-shift on other customers would fall as the credit rate steps down. At least half of the deployment would be for commercial and community solar installations standing at 100 kW.

“For systems of 100 kW or less, there is the standard offer with the decline rate,” Huber said. “For systems of over 100 kW, there would be a reverse auction for developers.”

According to OCA’s analysis, both options don’t completely eliminate the cost to other ratepayers, but does reduce it significantly. Under the Fixed Solar Credit Rate, it will cost ratepayers $81 million instead of $379 million over a 25-year span under traditional net metering.

“The Fixed Solar Rate will mature the solar market by gradually lowering the price to all ratepayers in a predictable way for the solar industry and solar adopters,” Huber said. “It breaks away from retail rate NEM but, in exchange, the solar industry gets business certainty and clarity and there will not be a big policy debate every year.”

Compared to Below’s TOU rate pilot project,”our TOU rate option is not as complicated and requires DG owners to ‘take the ride’ with rate fluctuations. The second option is for people who want certainty,” OCA’s Kreis said.

The utilities and the cost shift

Utilities are also proposing alternatives to the current net metering policy. One of the major IOUs, Liberty Utilities, proposed to replace the retail rate with a “default” rate for energy that they charge to customers who do not select retail electricity suppliers, according to John Shore, Liberty Utilities’ spokesman.

In addition to that, the utility would recoup lost revenue from distributed generation through distribution rates. In this manner, the utility hopes to also significantly reduce the cost-shift burden on other customers, a common argument from utilities seeking to change the net metering proposition.

New distribution generation owners will be billed and credited similarly to large installation owners, according to the utility’s filing. The customers would pay for imported electricity and be credited for the electricity they export at either the rate they pay their retail provider or at the approved avoided cost.

Customers who do not pay a distribution charge do not fully contribute to cover those costs, the utility says, and the peak output of solar arrays does not coincide with the system peak adequately to significantly reduce system needs.

For example, the filing reports, Liberty’s residential customer peak was February 15, 2015 at 6:00 p.m. and the region’s sun set that day at 5:36 p.m.

Liberty’s proposal would require bidirectional metering, sharing the costs between the customers and the utility. But, unlike the current net metering arrangement, charges and credits would be resolved within each month’s bill and excess credits would not be banked.

The Liberty proposal does not completely avoid a cost shift, Tebbets acknowledged. But under the current NEM policy, banking credits accentuates the cost shift by allowing customers to use them to essentially “receive the full retail rate for all their generation.”

By eliminating banking credits and reducing the credit for exported electricity to the energy service rate, “cost shifting will be significantly lessened,” Tebbets said, meeting the legislature’s dictate for the “avoidance of unjust and unreasonable cost shifting.”

Another residential demand charge proposal

For another New Hampshire IOU, Unitil, the primary focus is ensuring all customers pay for a distribution rate for using utility infrastructure, according to spokesperson Alec O’Meara told Utility Dive. Part of that structure would include a residential demand charge, which has proven controversial in other proceedings.

“The current two-part rate structure, which includes a rate for kilowatts delivered and a customer charge, should be replaced with a three-part charge for net energy metering customers, with the third part a demand charge based on peak load,” O’Meara argued. This would assure that all customer classes pay “an appropriate share of distribution costs” but could “keep distributed generation a viable option.”

The demand charge would recover only a portion of Unitil’s distribution system cost but separate it “from any external, societal and forward looking benefits that the Commission may deem appropriate,” according to testimony from COO Tom Meissner.

Meissner uses the term “prosumer” to describe DG owners because they both produce and consume electricity.

With the existing NEM policy, “prosumers and traditional customers pay very different amounts for identical demands on the distribution system,” Meissner argues. But "due to generation intermittency and hourly load characteristics, a prosumer’s peak demand for electricity may be no different than a traditional consumer.”

Unitil’s demand charge imposes the appropriate cost on prosumers “while continuing to allow net metering of energy purchases,” the filing argues. It would require AMI, but would send appropriate price signals to prosumers that can act as an incentive to better manage energy use and perhaps to invest in load control technologies like storage.

The failure of the current two-part rate and NEM policy to impose charges on DG owners for distribution costs “fundamentally violates the principle of matching and cost causation” in ratemaking theory, Edwin Overcast, director of Black & Veatch’s management consulting testified.

“The current rate design fundamentally ignores the fact that most of the system’s delivery costs to serve its customers are fixed and do not vary with the units of energy sold.”

Crafting a three-part rate structure would rectify those issues, he said. That structure would include a demand charge, a customer charge, and a volumetric rate with a TOU schedule.

In particular, the demand charge should be based on “maximum customer demand whenever it occurs,” according to Overcast. If based on a 15-minute interval, it can be a price signal that customers can respond to “with a lower per unit charge that will be easier to phase in with a lower impact on bills.”

For Eversource, the growth of distributed generation in its New Hampshire service territory means changes are needed to continue to meet legislative mandates to reduce costs for all customers and avoid ‘unjust and unreasonable cost shifting,’ according to testimony from Labreque. For that reason,  Eversource wants to “differentiate between the true avoided cost of generation on the system and the value of solar type analyses we fully expect other parties in the docket to lean on,” Labrecque told Utility Dive.

But solar advocates have pushed for New Hampshire to adopt a “benefit/cost methodology for net metered DG,” according to The Alliance for Solar Choice, an advocacy group. In its filing, Energy Freedom Coalition of America, a separate advocacy group backed by SolarCity, endorsed TASC’s caluclation of costs and benefits.

Eversource’s Labreque said there is “an important shortcoming in some of the value of solar studies, Eversource’s Labrecque said. Those studies find a very high value for exported DG, some as high as $0.30/kWh, whereas its wholesale market value in 2015 was only approximately $0.045 cents/kWh.

“Solar’s environmental values are already compensated through other policy mandates like tax credits, rebates, and renewable energy certificates,” he said. “There is a big divide between the concept of value and the concept to a utility of avoided cost. That division seems to be the debate.”

Boths sides agree a utility should be able to recoup fixed costs and revenues to meet short-term operating expenses, but they split over the proper compensation for excess solar energy from residential arrays, he added.

Moving forward

While both sides are split over compensation rates for distributed generation, Labreque is also skeptical over whether the resource can reduce transmission and distribution costs. There are likely to be discussions about integrated distribution system planning -- where both utilities and distributed generation developers collaborate to identify locations on the grid where the resource is most valuable.

“But relying on a non-utility project to solve a problem that is 100% the utility’s obligation is a difficult threshold for us to cross,” Labrecque said.  “It is a stretch to think of solar alone as a reliable solution but the higher potential of solar with batteries would come at a higher cost. These things would need to be worked out, maybe in a pilot program. The future of integrated planning does involve non-utility alternatives but we have to be purposeful about it.”

Part of that reasoning means finding a well-designed successor tariff that “can lead to an increase in the adoption of these technologies.”

“Traditional retail net metering tariffs provide minimal incentives for customers to invest in storage devices and demand control technologies,” Labrecque’s filing noted.

Whether or not utilities and solar advocates can come together to find common ground remains uncertain at this point in the process. NHSEA’s Epsen has not yet seen signs of compromise from the IOUs but “the recent compromise in the energy efficiency proceeding makes me think we can find common ground,” she said.

Some utilities agree.

“We have a long, well established history of working collaboratively with the New Hampshire commission on complex issues like this,” Unitil’s O’Meara said. “Every docket is different, but that settlement is certainly an example of a collaborative effort.”