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№ 49 · appended

New Jersey proposes $200 per kW a year for home batteries, and its own worked example pays $540

Ten years of performance-linked payment on a battery in someone’s garage is a real transfer of value to the edge, and aggregators are named participants rather than excluded ones, so the utility is not the only party that can stand between a household and the money. The argument is about where risk lands. Performance is measured as the worst hour of a dispatch event against a nameplate power rating, which puts battery duration, state of charge at the moment of the call, and event length entirely on the household’s payment rather than on the utility’s obligation. Staff’s own example realises about a quarter of the headline rate. A household comparing installer quotes reads "$200 per kW"; the programme’s model expects to pay $540 on a Powerwall-class system. That gap between an advertised rate and a structurally unreachable one is the thing a reader with a roof and a quote in hand needs to see before signing a ten-year agreement.

The New Jersey Board of Public Utilities is offering households a ten-year contract for their home battery. The headline rate is $200 per kilowatt per year. The worked example inside the Board's own proposal pays $540 a year on an 11.5 kW system, which at the headline rate would earn $2,300. The gap between those two numbers is not an error. It is the design.

On 19 August 2026 the NJBPU announced the release of a straw proposal dated 17 August 2026 for Phase 2, Distributed Energy Storage Capacity Block 1 of the Garden State Energy Storage Program, filed under docket numbers QO26030099 and QO26040116. Block 1 targets up to 150 MW of new behind-the-meter residential storage statewide, against a statutory goal of 2,000 MW of storage in New Jersey by 2030. The state's four electric distribution companies, Atlantic City Electric, Jersey Central Power & Light, PSE&G and Rockland Electric, would administer enrolment, call dispatch, track performance and issue payments under Board oversight.

Written comments closed at 5 p.m. Eastern on 10 September 2026, after a virtual stakeholder meeting on 3 September. Board Staff expect to bring a minimum filing requirements Order to the Board in October 2026, with EDC response petitions in December 2026 and Block 1 opening by July 2027.

How the payment is actually calculated

The Incentive Rate is $200 per kW of Awarded Storage Capacity per year, and the straw proposal is explicit that this is the maximum available to a project achieving a 100 per cent Performance Factor. Awarded Storage Capacity is the system's nameplate AC output in kilowatts, not its energy capacity.

The annual payment is the Incentive Rate multiplied by Awarded Storage Capacity multiplied by the Performance Factor. The Performance Factor is where the money goes. It is the average, across every dispatch event in the performance year, of Dispatch Event Min Output divided by Awarded Storage Capacity. Dispatch Event Min Output is defined as the minimum hourly discharge across all Performance Intervals within that event. The measure is not average output during the event and not peak output. It is the worst hour.

Staff's own illustration uses a system of 11.5 kW and 13.5 kWh, which is a Powerwall-class configuration. It assumes 35 dispatch events, 125 Performance Intervals, an average event duration of 3.5 hours and an average minimum discharge of 2.7 kW. That yields a Performance Factor of 23.5 per cent and an annual incentive payment of $540.

The arithmetic behind the 23.5 per cent is worth doing on the document's own assumptions. Holding 11.5 kW for 3.5 hours would take about 40 kWh. The battery holds 13.5 kWh. A full, perfectly executed discharge across a 3.5 hour event therefore tops out near 3.9 kW sustained, and the example's 2.7 kW leaves headroom below even that. The Performance Factor cannot approach 100 per cent for any battery whose power-to-energy ratio is typical of residential hardware, because the metric compares a duration-limited output against a nameplate power rating. A household reading "$200 per kW" is reading a number that the programme's own model does not expect to pay.

There is one relief valve. Where a resource discharges below its Awarded Storage Capacity because the EDC's own dispatch instruction told it to, the standard Performance Factor calculation is set aside, and the resource is credited with the average performance it would otherwise have achieved.

The dispatch obligation

Preliminary event parameters, which Staff say will be refined through the minimum filing requirements process, allow up to 20 events per summer season from 1 June to 30 September, including the five PJM coincident peaks, and 10 events per winter season from 1 December to 28 February, with no more than 35 events in a calendar year inclusive of events called outside those windows. Test calls to confirm readiness do not count toward the total. Standard events carry two hours of advance notice. Emergency events carry ten minutes.

Who can take part, and who cannot

The participant is not necessarily the household. The straw proposal defines a Participant as the entity authorised to enrol, manage and receive incentives for a project, "which may include the metered customer, a Third Party Owner, an Aggregator, or another authorized third party." The glossary defines Aggregator separately, as an entity that enrols, configures, manages, controls or coordinates systems on behalf of one or more host customers. Third-party aggregation is written into the design rather than excluded from it, which is worth stating plainly because coverage of the release did not mention it.

Eligibility is narrow in other ways. Only new systems qualify: retrofits, repowered assets and expansions of existing installations are out unless future guidance says otherwise. Front-of-the-meter resources are out. So are projects under bilateral contract with a data centre or other new large load. And eligibility is limited to residential customers who have not taken a third-party supply rate that passes through wholesale energy, capacity or transmission charges, which removes exactly the households already exposed to the prices the programme is trying to avoid. Applications carry a non-refundable $50 fee, intended to deter speculative reservations of scarce capacity.

Staff also encourage participants to install hardware capable of speaking IEEE 2030.5 or SunSpec Modbus TCP, with OpenADR 2.0b or 3.0 for dispatch signalling, specifically so that a participant retains the option to exit Block 1 later for a future virtual power plant tariff. The exit is contemplated in the document, not foreclosed.

Who pays

Incentive costs are recovered through a non-bypassable per-kWh charge applied to all customer classes. Every ratepayer funds the payments; only new residential battery owners receive them.

Staff ran the cost-benefit analysis against that objection directly, splitting it into All Ratepayers and Non-Participant Residential Ratepayers. The reported benefit-cost ratios are 2.16 and 1.79 respectively, the second intended to show that households who never enrol still come out ahead through reduced supply and delivery costs after paying their share. Those ratios rest on stated assumptions, including that only 20 per cent of participants sit on time-of-use rates, and a deliberately conservative treatment of capacity value chosen because PJM capacity prices are expected to sit at the cap regardless of new deployment.

On the rate itself, Staff modelled a total installed cost of $1,250 per kWh and calculated a revenue gap indicating an incentive level of $300 per kW. They recommended $200 per kW anyway. The comparison table in the proposal lists Connecticut's energy storage solutions programme at $300 per kW with 1,235 customers and roughly 15 MW, ConnectedSolutions in Massachusetts and Rhode Island at $275 per kW with 5,251 customers and roughly 29 MW, and Luma Energy's customer battery programme in Puerto Rico at $1 per kWh, described as equivalent to $280 to $400 per kW, with 81,000 customers and roughly 500 MW.

Why it matters

A ten-year performance payment on a battery in someone's garage is a real transfer of value to the edge, and the inclusion of aggregators as named participants means the utility is not the only party that can stand between a household and the money. Both of those are worth crediting before the criticism.

The criticism is about where risk lands. The Performance Factor measures the worst hour of an event against a nameplate power rating, which means every constraint the household cannot control, battery duration, state of charge at the moment of the call, an event that runs longer than the battery, falls on the household's payment rather than on the utility's obligation. The programme keeps the right to call 35 events a year with as little as ten minutes of notice, and pays for what the battery managed in its weakest hour. That is a defensible way to buy firm capacity. It is not what "$200 per kW" communicates to a homeowner comparing quotes, and Staff's own example shows the realised figure at roughly a quarter of it.

The second thing worth watching is the gap between the $300 per kW that Staff's revenue-gap model produced and the $200 per kW they recommended. The proposal does not explain the reduction in the section that states it. A programme that under-prices against its own model, and then measures performance on the least generous available basis, is making an affordability choice at the expense of subscription. Whether 150 MW fills at that price is the question the October Order will answer.

What is still unknown

Whether an enrolled resource may simultaneously participate in a PJM wholesale aggregation, and on what terms, is not addressed in the straw proposal as read. Nor is it stated whether any energy is reserved for the household's own backup during a dispatch event, which matters given that Staff acknowledge most residential batteries installed in New Jersey to date were bought for resilience rather than revenue.

The comparison table presents Connecticut, ConnectedSolutions and Luma as incentive levels without stating whether those programmes measure delivered performance on the same minimum-hour basis. If they pay on average performance, the comparison overstates how close $200 per kW sits to its peers. [NEEDS DATA: performance measurement basis for the three comparison programmes.]

How the 150 MW splits across the four EDCs is left to the minimum filing requirements process, as is the final event count. [NEEDS DATA: per-EDC capacity allocation for Block 1.] The straw proposal also does not say what happens to a household's payment if it declines a dispatch call outright rather than underperforming one.

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