Is New Hampshire on the verge of battery energy storage history?
The only question left to be settled is a big one: Should utilities own behind-the-meter batteries?
A small investor-owned utility in New Hampshire may be on the verge of regulatory approval for one of the most ambitious U.S. tests yet of utility-owned, customer-sited battery energy storage systems.
In the process, regulators and stakeholders of the DE 17-189 proceeding are wrestling with a question of vital interest to the rest of the 3,000-plus U.S. utilities: Should a utility own customer-sited storage or is it a distributed energy resource (DER) that should be left to private sector providers?
Utilities have already seen the benefits that large-scale battery energy storage offers in shaving peak demand, providing grid services, and making systems more flexible. There is a clear opportunity to use customer-sited battery storage in the same way. But the question of how far utilities can intrude into markets so far served by private sector vendors must first be answered.
Vermont goes first
The only major U.S. utility-owned, behind-the-meter (BTM) battery storage is the Green Mountain Power (GMP) pilot project, according to GTM Research Energy Storage Analyst Brett Simon. GMP, the dominant Vermont electricity provider, is installing 2,000 behind-the-meter Tesla Powerwalls that will provide dispatchable energy and other grid services to New England’s wholesale electricity markets. Customers pay a one-time $1,300 fee or a monthly $15 fee to participate.
New Hampshire's Liberty Utilities wants state regulators to approve a pilot project of 1,000 utility-owned Tesla Powerwalls. They would be provided to customers for a one-time $1,000 fee or a monthly $10 fee.
Approximately 300 would be installed in homes along a circuit where Liberty wants to test the viability of a non-wires alternative to a distribution system infrastructure upgrade. The other 700 batteries would be available to customers who apply to participate in the pilot.
Like GMP, Liberty would use the BTM storage to reduce its customer base’s costs for power market peak demand charges and to provide other system services. Liberty would also use the pilot to introduce a new time-of-use (TOU) rate to support customer participation.
Private sector DER providers and the New Hampshire Public Utilities Commission (NHPUC) Staff say the pilot should not be approved. Solar and storage providers Sunrun and ReVision Energy argue Liberty customers would benefit more by working through the private sector. Staff argues the proposal is too costly and not technically workable.
Liberty wants ownership
"We believe the utility can do this just as well as the third-party providers," Liberty Senior Rates and Regulatory Affairs Analyst Heather Tebbetts told Utility Dive. "Part of the pilot addresses a non-wires alternative program, and we believe utility ownership for it is appropriate. Since we will own a portion of the batteries, we felt owning all of them for the pilot was appropriate."
The parties are now engaged in settlement talks. Several confided to Utility Dive they are optimistic about finding common ground. If they do not reach an agreement by early July, the debate will go to commissioners for a ruling.
The utility proposal
As the power grid takes on new challenges, like high renewables penetrations and the need for greater flexibility, residential storage can be "another avenue for utilities to expand their business models," GTM Research's Simon, emailed Utility Dive.
Liberty Utilities expects the 5 MW nameplate capacity of the 2,000 batteries to save its customers "about $693,000 a year in transmission costs," according to its NHPUC filing. The savings will come in the near term by reducing local and regional peak demand period transmission charges.
Over the pilot’s proposed five-year period, Liberty will incur cost savings through use of batteries as a non-wires alternative, the filing adds. Through the pilot, Liberty expects to get a better understanding of "how batteries interact with the distribution system, how to efficiently utilize the stored energy, and the overall savings in avoided distribution system upgrades."
The cost for each installation, including battery and software, is estimated at $7,000 to $9,000, Liberty reports. The utility will request cost recovery through rates in the rate case that follows deployment.
"Because only we can discharge the battery to the grid, we thought it appropriate to incentivize customers to reduce their load during that high demand period by giving them the retail rate credit."
Senior Rates and Regulatory Affairs Analyst, Liberty Utilities
Chapter 374-G:4 of NH Public Utilities Title XXXIV allows the utility to own and ratebase DER representing up to "6% of the utility's total distribution peak load," Tebbetts said. "But the statute requires us to deploy it efficiently and cost-effectively, which is why our proposal includes time-of-use rates and a non-wires alternative."
Customers will have access to the stored power in their batteries "except when a demand peak is predicted for the following day," the filing reports. Liberty will control the batteries ahead of and during those events.
Tebbetts said the first customers to get batteries will be ones on a circuit where the distribution system needs support. "The rest will go to customers who apply, first come, first served," she added.
The TOU rate will have a "Critical Peak" pricing period on weekdays from 2 p.m. through 7 p.m. and an "On-Peak" period from 7 p.m. through 8 a.m. The "Off-Peak" period will be 8 a.m. through 2 p.m. weekdays and all weekends and holidays.
Liberty’s current voluntary TOU rate is little used, Tebbetts said. Customers in the pilot will have programmable software to make using the new rate more convenient. An increased emphasis on customer education will show them its advantages.
Typically, batteries will be charged nightly, when rates are lowest, and used automatically the next day, when rates are highest, she said. The utility is essentially arbitraging energy for its customers.
Outside pre-announced peak demand periods, customers will be able to make their own decisions about the stored power, but only the utility can export it, Tebbets said.
Customers will be notified of forecasted peaks a day in advance. Ahead of the event, Liberty will take control of their batteries through the software, to assure that they are fully charged. During the event, "the batteries automatically dispatch to serve the customer’s load first and excess would go to the grid to help flatten overall peak demand," she said.
For generation exported to the grid, the customer’s bill will be credited at the retail net energy metering (NEM) rate, she added. "Because only we can discharge the battery to the grid, we thought it appropriate to incentivize customers to reduce their load during that high demand period by giving them the retail rate credit."
Solar owners participating in the pilot can, if they choose, take advantage of the Off-Peak-to-Critical-Peak arbitrage and export their solar generation to the grid at the NEM rate, according to the filing.
What Staff doesn’t like
Testimony from NHPUC Utility Analyst Elizabeth Nixon reports that the pilot is "substantially based" on the GMP pilot. But Liberty will not partner with Tesla on marketing, customer education and acquisition, site design, installation, or operation and maintenance costs, which makes it potentially more difficult and costly, she added.
Liberty "has not prepared a detailed plan for implementation and administration of the pilot," Nixon said. It does not have a plan for marketing, has not formulated a peak period forecasting methodology, and has no data collection and evaluation program.
In addition, GMP has "about six times more total customers than Liberty," Nixon pointed out. That means GMP needs to enroll "about 0.7%" of its customers but Liberty needs to enroll "over 2% of its customers" to reach full deployment for the pilot.
GMP’s pilot will last for 18 months, while Liberty’s proposal is for a ten-year program and a five-year study period, "far longer than the typical one-year to three-year time frame for a pilot," she added.
On cost, Nixon disputes Liberty’s estimated net present cost of $1.1 million. The NHPUC Staff benefit-cost analysis found "a net cost of $2.8 million," Nixon reported.
In short, Nixon testified, "we are concerned that Liberty has not done enough upfront planning and preparation to successfully implement the proposed pilot program."
NHPUC Utility Analyst Kurt Demmer evaluated the technical details of the proposal. He identified "system deficiencies" and inadequate "real time data" to support the non-wires alternative and technical shortcomings that make achieving the projected peak reductions questionable.
These concerns can be addressed, according to testimony by Stategen Consulting VP Lon Huber. He recommended adding a performance incentive and altering assumptions about the amount of peak demand reduction. Both, he said, might better align differences on the proposal's net present value.
The criticisms of the proposal's costs are "Staff doing its job," Liberty's Tebbets said. "But we hope all parties can come to a settlement on this pilot because it will set the bar for the state and the regions." She declined to comment in further detail on the critique.
Third-party providers protest
Liberty’s proposal is fundamentally flawed because it does not include a test of alternatives to utility-owned battery energy storage, according to testimony on behalf of solar and battery providers Sunrun and Revision Energy by Justin R. Barnes, director of research for energy sector consultant EQ Research. Because of this, utility ownership of BTM batteries as proposed by Liberty would impede emergence of "a competitive residential energy storage market in Liberty’s service territory."
The pilot’s large size leaves few early adopters in the market for third party providers, Barnes testified. Giving the utility full control leaves no way for private providers to participate. And the new, storage-enabling TOU rate would not be available to customers outside the pilot.
Barnes’ alternative proposal is based on GMP’s newer Bring-Your-Own-Device (BYOD) program, but includes a shared savings mechanism that could allow both private providers and the utility to achieve peak load reductions.
It would limit utility-owned storage to 25% of the program. Instead, participants would own the majority of storage devices marketed and aggregated by private sector providers. The customers or their aggregators would have "long-term, pay-for-performance contracts" with the utility, Barnes wrote.
Customers or their aggregators would control the devices, earn returns in the same way as utility-owned assets, and have the same TOU rates. Dispatch would be by the utility, in cooperation with customer-owners and aggregators, Barnes wrote.
A "shared savings mechanism" offers "a new utility revenue opportunity," Sunrun Public Policy Director Chris Rauscher told Utility Dive. If Liberty, which knows its system better than the aggregators, accurately notifies aggregators of coming system peaks, it would get a share of the savings that would go to its entire rate base.
"If we reach agreement, this can show the rest of the country the way forward for customer-sited battery storage."
Public policy director, Sunrun
"The utility will not be burdened with complications of ownership, like customer acquisition, installation, and maintenance," Rauscher said. "And the plan opens a competitive market for battery energy storage in New Hampshire."
Unlike Liberty’s proposal, Barnes’ plan would cost Liberty customers almost nothing because aggregators would only be paid if they perform, he added.
Liberty's Tebbetts declined to comment on Barnes' plan.
Rauscher said that despite the differences between Sunrun and Liberty on the ownership question, the utility deserves credit for recognizing the BTM storage opportunity. Early settlement discussions have been collaborative, he added. "If we reach agreement, this can show the rest of the country the way forward for customer-sited battery storage."
The settlement that could be
Stakeholders contacted by Utility Dive were disinclined to comment for attribution, because of concern about impacting the settlement hearings. But they said there was value in Liberty's proposal and in alternatives proposed by other interveners.
The settlement hearings, which are expected to deliver a compromise by early July, if there is one, can lead to a plan that works, Liberty's Tebbetts agreed. "There is benefit in having both utility-owned batteries and third party-provided batteries available to customers," she said.
"We can bring costs down by adding competition."
Staff attorney, Conservation Law Foundation
The basis for that compromise is the unique value in Liberty’s non-wires alternative and new TOU rate, and in the importance of a competitive market, according to Melissa Birchard, a docket intervenor and staff attorney with Conservation Law Foundation (CLF).
The non-wires alternative would be a test of BTM storage as a way to defer or avoid distribution system expenditures, she said. If customers respond to the TOU rate, it would be an important way to validate the usefulness of price signals in addressing peak demand. Other important ideas being discussed are targeted energy efficiency and better customer education, she added.
CLF supports a limited, utility-owned battery pilot because the non-wires alternative is "cutting edge," Birchard told Utility Dive. Liberty should focus on that, which would require owning between 300 and 500 batteries. That would leave half the pilot to competitive providers.
The new TOU rates "should be made available to everybody, either in this pilot or in the near future," she added.
Market competition drives innovation and leads to better customer service, Birchard said. "But taking advantage of Liberty’s ready access to customers and its ability to recover costs for something that is truly cutting edge also makes sense. That's what a pilot is for."
It is reasonable for Liberty to control the non-wires alternative, but the shared savings proposal, suggested by Barnes, is also reasonable, she added. "A pilot that tests both business models is conceivable."
Birchard agreed with Tebbetts that Staff’s cost concerns are addressable. "We can bring costs down by adding competition," she said.
"Regulated utilities and competitive actors can work together to reach customers, to educate them, and to provide them with the best combination of technology and services," Birchard said. "This pilot can prove that there’s a place for both in a modern energy industry."