New Jersey’s Board of Public Utilities is shaping a statewide virtual power plant program that explicitly includes battery storage as an eligible resource, marking a structural shift from demand-response-only frameworks toward aggregated distributed energy resources that can inject power during peak congestion. Utility stakeholders at a July meeting emphasized that utility-owned storage assets could directly alleviate transmission bottlenecks, while program administrators warned that high customer attrition rates – already a persistent issue in existing demand response offerings – require fundamentally redesigning enrollment, compensation, and communication around participant experience.
New Jersey’s VPP Framework Moves Beyond Demand Response
The Garden State’s move toward a battery-eligible VPP program reflects a deliberate policy choice to treat distributed storage as a grid asset class rather than a behind-the-meter bill-management tool. New Jersey’s Clean Energy Act of 2018 set a 2,000 MW energy storage target by 2030, and the state’s Energy Master Plan calls for 100 percent clean electricity by 2035. But until recently, the state’s primary distributed resource programs – notably the Solar Renewable Energy Certificate (SREC) successor programs and the existing demand response aggregations – treated storage as an afterthought or excluded it entirely from wholesale market participation pathways.
The July stakeholder meeting, convened by BPU staff and the state’s electric distribution companies (EDCs), focused on the Straw Proposal for the VPP program’s design parameters. According to Utility Dive’s reporting, utility managers raised two operational priorities: first, that utility-owned or utility-contracted storage sited at strategic substations or feeders could provide targeted congestion relief on the PJM Interconnection system, particularly in northern New Jersey corridors where load growth from data centers and electrification is outpacing transmission upgrades. Second, program administrators stressed that customer-centric design – simplified enrollment, transparent compensation, and proactive communication – is essential to reducing the 15-25 percent annual attrition rates seen in the state’s current demand response programs.
This dual focus reveals a tension at the heart of VPP design nationwide: the grid value of aggregated batteries is highest when they are dispatchable, predictable, and sited where the grid needs them most, but the customer economics and experience that drive enrollment and retention often pull in the opposite direction – toward behind-the-meter installations optimized for bill savings or backup power, not grid services. New Jersey’s program design will need to resolve this tension through compensation structures that stack wholesale capacity and energy value with distribution-level locational incentives, a mechanism few states have successfully implemented at scale.
Utility-Owned Storage as Congestion Management: A PJM-Specific Play
Analysis: The emphasis on utility-owned storage for congestion relief is a direct response to PJM’s capacity market dynamics and New Jersey’s transmission topology. Northern New Jersey – particularly the Public Service Electric & Gas (PSE&G) and Jersey Central Power & Light (JCP&L) territories – faces chronic congestion on 230 kV and 500 kV corridors feeding the New York metropolitan load pocket. PJM’s 2024 Regional Transmission Expansion Plan (RTEP) identifies over $2.3 billion in baseline upgrades for the PSE&G zone alone through 2028, driven largely by load growth from data centers in the Newark-Elizabeth corridor and electrification-driven demand increases.
Utility-owned storage deployed at distribution substations can provide non-wires alternatives (NWAs) that defer or avoid a subset of these transmission investments. A 2023 Brattle Group study for the Edison Electric Institute estimated that strategically sited distribution-level storage can provide congestion relief at roughly 40-60 percent of the levelized cost of equivalent transmission upgrades, when accounting for avoided line losses and ancillary service revenues. If New Jersey’s VPP program creates a clear revenue stream for utility-owned assets participating in both PJM markets (capacity, energy, regulation) and distribution-level congestion management, it could unlock a deployment model that has struggled to pencil out in other jurisdictions – where utilities often face regulatory barriers to owning storage or lack a defined cost-recovery mechanism for NWA services.
By comparison, California’s Distribution Resources Plans (DRPs) and New York’s Value of Distributed Energy Resources (VDER) tariff have attempted similar locational valuation but have not yet produced a scalable utility-owned storage procurement target tied to specific congestion zones. New Jersey’s advantage is a more concentrated utility landscape (four EDCs serving the entire state) and a BPU with explicit statutory authority to approve NWA investments through base rate cases or the Clean Energy Act’s storage mandate. If the VPP program includes a utility procurement target – for example, 200-300 MW of utility-owned or utility-contracted storage by 2028 sited in identified congestion zones – it would represent one of the first state-level programs to directly link VPP participation to transmission deferral economics.
Customer Attrition: The Hidden Cost of Poor Program Design
Analysis: The 15-25 percent annual attrition figure cited by program administrators aligns with national demand response experience but is rarely discussed in VPP policy circles. A 2022 Lawrence Berkeley National Laboratory (LBNL) review of residential demand response programs across 10 states found median participant retention of 72 percent after three years – meaning nearly 30 percent of enrolled customers drop out within the typical program cycle. Attrition drivers include: opaque compensation (customers don’t understand when or why they’re paid), disruptive event notifications (often delivered via text or email with minimal lead time), and a perceived imbalance between inconvenience and reward (typical residential DR payments of $40-$80 per summer season).
For a VPP program that includes batteries – which represent a $10,000-$20,000 customer investment (before incentives) – attrition is far more costly. Each lost participant represents not just foregone grid capacity but a stranded asset that may not be re-enrolled. The industry rule of thumb for customer acquisition cost (CAC) in residential energy programs ranges from $500-$1,500 per enrolled site when including marketing, onboarding, and device provisioning. At 20 percent annual churn, a 50,000-site VPP would need to acquire 10,000 new participants yearly just to maintain scale, implying $5-15 million in annual CAC – a line item that can erode program cost-effectiveness faster than any technology cost.
The stakeholder meeting’s emphasis on “customer-centric design” suggests New Jersey may adopt design elements proven to reduce churn: fixed seasonal payments regardless of event count (decoupling compensation from dispatch frequency), mobile apps with real-time earnings visibility, and opt-out windows that preserve autonomy without penalizing re-enrollment. Vermont’s Green Mountain Power (GMP) residential battery program – which offers a fixed annual bill credit of $850 for a 10-year commitment in exchange for full dispatch rights – has achieved under 5 percent annual attrition since 2018. That model’s success hinges on simplicity: one payment, one contract, no event-by-event accounting. If New Jersey’s VPP adopts a similar fixed-compensation layer for battery participants, it could set a new standard for retention in aggregated storage programs.
Who This Affects
- Utility planners: The program creates a pathway to rate-base storage assets that serve dual purposes – PJM capacity market revenue and distribution congestion relief – but requires filing NWA business cases with BPU that quantify avoided transmission costs against storage capital expenditure, a modeling exercise most New Jersey EDCs have not yet formalized.
- Storage developers and aggregators: Third-party VPP operators gain a defined wholesale market access route in PJM through the program, but must compete with utility-owned assets that may receive preferential siting or cost recovery; developers should model bid strategies assuming utility storage clears capacity at lower offer prices due to rate-based return requirements.
- Policy analysts and regulators: New Jersey’s VPP design will test whether a state can simultaneously optimize for transmission deferral (a utility-centric value stream) and customer retention (a market-participation value stream) without cross-subsidization – a precedent that could inform FERC Order 2222 compliance filings in other PJM states.
- Grid operators (PJM): The program’s scale – potentially 500-1,000 MW of aggregated DERs by 2030 if aligned with the state’s storage target – will require PJM to refine its DER aggregation model for capacity accreditation, particularly around seasonal availability and state-of-charge constraints that differ from traditional generation.
What to Watch Next
- BPU Straw Proposal finalization (Q4 2024): Look for specific MW targets for utility-owned vs. third-party storage, locational adders for congestion zones, and whether the program adopts a fixed-compensation layer for residential batteries to address attrition.
- EDC NWA filings (2025-2026 rate cases): PSE&G, JCP&L, Atlantic City Electric, and Rockland Electric will likely propose utility-owned storage projects tied to specific congested feeders; the BPU’s approval or modification of these filings will signal how aggressively the VPP program’s congestion-relief mechanism is operationalized.
- PJM DER aggregation rule updates (2025): PJM’s compliance with FERC Order 2222 continues to evolve; any changes to the minimum participation threshold (currently 100 kW) or capacity accreditation methodology for limited-duration storage will directly affect New Jersey VPP economics.
- Customer enrollment metrics (first 12 months post-launch): Track quarterly enrollment, opt-out rates, and event participation rates by customer class – residential vs. commercial/industrial – to assess whether the program’s customer-centric design translates into sustained participation or repeats the attrition patterns of legacy DR.
Bottom Line
New Jersey’s battery-eligible VPP program is the first state-level effort to explicitly structure distributed storage participation around transmission congestion economics rather than just capacity or energy arbitrage. If the BPU finalizes a design that pairs utility-owned storage procurement targets for constrained corridors with a fixed-compensation model that solves the attrition problem, it creates a replicable template for other PJM states facing similar load-growth-versus-transmission-timeline gaps. The critical test is whether the program’s compensation stack – PJM capacity + energy + regulation + distribution locational adder – can be made transparent and durable enough to finance both utility and third-party assets at the 2,000 MW scale the state’s storage mandate envisions.
Read the full report at Utility Dive
Note: facts and figures attributed above to Utility Dive reflect that outlet's original reporting. Broader context, cross-sector connections, and forward-looking scenarios reflect independent analysis by our editorial team.
About this article: Drafted by Energy Ai with AI-assisted research and writing based on public reporting, then reviewed under our editorial process before publication.
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