The VPP Procurement Wave Is Here

Virtual power plant procurement in the United States passed a threshold in April 2026 that separates academic interest from real spending. Two state-level actions landed within two weeks of each other: Minnesota approved a $430 million utility-owned battery VPP, and Virginia enacted a law that requires its two largest utilities to petition for grid utilization metrics and directs its regulator to analyze VPPs and other non-wires alternatives. One is an approved program; the other is a regulatory deadline.

At the same time, battery storage costs crossed a line that makes the economics nearly automatic. BloombergNEF reported in February 2026 that the levelized cost of a 4-hour battery system fell 27% year-over-year to $78/MWh, while combined-cycle gas rose 16% to $102/MWh. Batteries are now cheaper than gas peakers on a pure cost basis.

But the story is more complicated than “batteries got cheap, so utilities bought them.” A pricing fracture between utility-scale and distribution-scale systems means smaller utilities and cooperatives are not seeing the same savings. And the equipment bill of materials for a VPP extends well beyond batteries. This is an equipment pipeline story, and it starts with what just happened in two states.

Minnesota’s $430 Million Bet on Utility-Owned Batteries

On April 2, 2026, the Minnesota Public Utilities Commission approved Phase 2 of Xcel Energy’s Capacity*Connect program. The numbers: up to 200 MW of distributed battery energy storage, deployed in 1-3 MW units across Xcel’s distribution grid, with full buildout by 2028 (Utility Dive, April 2026).

Total program cost: $430 million. That puts the implied installed cost at roughly $2,150 per kilowatt, a premium over utility-scale pricing but competitive for distributed applications that provide multiple grid services.

Sparkfund is handling deployment. The model is utility-owned, meaning Xcel retains ownership and dispatch control of every battery. This is the detail that drew opposition. Vote Solar and a coalition of clean energy advocates argued the decision shuts out third-party developers and concentrates market power with the incumbent utility (Vote Solar, April 2026).

The PUC attached conditions: battery placement in underserved communities, an apprenticeship partnership, and an independent program evaluation. Regulators see the equity implications of VPP siting decisions, not just the capacity math.

The procurement signal is the scale. Two hundred megawatts of 1-3 MW distributed battery systems means dozens of individual installations. Each one needs interconnection equipment, protection relays, a communication backbone, and in many cases, a transformer or switchgear upgrade. The equipment supply constraints we covered in the Triple Squeeze apply directly here.

Xcel is also building a separate 600 MW utility-scale BESS at its Sherco site. Both projects address MISO capacity shortfalls as coal plants retire across the Upper Midwest.

Virginia HB 434: Grid Utilization Metrics and a Non-Wires Review

Virginia took a different route. Instead of approving a single program, the state passed a law requiring grid utilization metrics that, as the SCC finds appropriate, may inform how it weighs future utility requests to recover capital costs.

HB 434, enacted as 2026 Acts Chapter 611 and approved April 13, 2026, requires each Phase I and Phase II utility to petition the State Corporation Commission for approval of electric grid utilization metrics no later than October 15, 2026. In approving metrics, the SCC is to include, as appropriate, a timeline for each utility to increase grid utilization and a description of how the metrics may inform future cost-recovery requests for capital investments. The act sets no date for that order. (Corrected 2026-10-02: an earlier version gave a November 1 filing date and a July 1, 2027 order deadline; the enacted text supports neither.)

Translation: the utilities must measure how fully they use the grid they already have, against metrics the SCC approves. And the SCC must analyze whether energy storage, VPPs, distributed generation, flexible transmission and the other listed alternatives could raise that utilization.

The bill names the alternatives explicitly. Energy storage. Customer-owned capacity. Utility-owned distributed generation. Virtual power plants. Flexible transmission and TSTATCOMs. Synchronous condensers. Power quality monitoring equipment. This is not a vague directive to “consider alternatives.” It is a checklist.

The AMI connection matters for procurement teams. The act does not mention AMI. But the SCC must decide how utilization metrics apply at the feeder and substation level, and measuring at that level depends on meter and sensor data. AMI 2.0 meters can collect up to 50 million times more data than first-generation advanced meters (PV Magazine, February 2026). If the approved metrics call for feeder-level reporting, that data need reaches communications infrastructure, SCADA/DMS and grid sensors.

Dominion serves about 2.7 million customers. Appalachian Power covers roughly 530,000 (LegiScan, March 2026). Their petitions are due by October 15, 2026. The act asks for utilization metrics, not equipment purchases, so watch what the SCC approves before assuming RFPs for sensors, voltage regulators, reclosers or monitoring systems.

Read the Capacity Figure With Its Source and Date

Wood Mackenzie’s September 17, 2025 market release reported 37.5 GW of behind-the-meter flexible VPP capacity in North America. That is a market total, not California enrollment or a measure of power delivered during one emergency.

The same release reported 13.7% capacity growth. Company deployments, unique offtakers and monetized market and utility programs each grew more than 33%. More programs did not mean capacity grew at the same rate.

For procurement, ask what the proposed program can deliver at your required location and duration. Keep enrolled capacity, accredited capacity and measured dispatch separate in the bid comparison. A national market total cannot answer that local question.

---

Battery Storage Procurement Prices: Two Markets, Not One

The cost story matters, but it is not uniform.

Anza Renewables pricing data, corroborated by Wood Mackenzie analysis, shows a clear fracture in U.S. battery storage pricing as of Q1 2026 (Utility Dive, April 2026). Utility-scale AC systems dropped 20.9% since May 2025. Distribution-scale AC systems sit at roughly $203/kWh and have barely moved since November 2025.

The cause: battery suppliers are prioritizing data center and independent power producer clients. Distribution-scale orders are, in Anza’s framing, an “afterthought.”

This pricing gap hits municipal utilities and cooperatives hardest. A co-op buying a 2 MW battery for a VPP program pays $203/kWh while a large IOU procuring a 100 MW utility-scale system gets 20% cheaper pricing. The math that makes VPPs attractive at utility-scale does not automatically transfer to smaller buyers.

And there is a compliance layer. Of 79 products in Anza’s tracking dataset, 51% carry “high” or “highest” Foreign Entity of Concern (FEOC) risk (Utility Dive, April 2026). FEOC-compliant products cost more. For utilities subject to federal funding requirements or Buy America provisions, the pricing floor is even higher than the headline $203/kWh. We covered related compliance requirements in our piece on NFPA 800 battery safety standards, which add another layer to the procurement equation.

The 2026 deployment forecast remains enormous regardless: 70 GWh and 35 GW of BESS installations across the U.S., per SEIA (SEIA, Q1 2026). That volume is real. But smaller utilities need to know that the prices in the headline forecasts may not match what shows up on their quotes.

The Equipment BOM Goes Far Beyond Batteries

VPP utility programs get talked about as battery programs. They are not. Every VPP installation connects to a distribution circuit designed for one-way power flow. Bidirectional current changes the equipment requirements at every point between the battery and the substation.

Here is what procurement teams are actually buying when they build out a VPP program:

DERMS platforms. The distributed energy resource management system is the software layer that turns a collection of batteries into a single dispatchable resource. No DERMS, no VPP. DERMS procurement is growing alongside every program approval.

Smart inverters. Grid-interactive inverters with IEEE 1547-2018 compliance are required for any DER that feeds back to the grid. Spec requirements are tighter than what was standard three years ago.

AMI 2.0 meters and communications. The meter is just the endpoint; backhaul communications, data management, and SCADA/DMS integration are separate procurement lines.

Grid-edge protection equipment. Reclosers, sectionalizers, and voltage regulators need to be rated for bidirectional power flow. A recloser specified for radial feed may not trip correctly when power reverses direction. These upgrades get missed in early-stage VPP planning and show up as change orders later.

Transformers and switchgear. Battery systems in the 1-3 MW range typically require a dedicated pad-mount transformer and medium-voltage switchgear. The data center demand wave is already stretching transformer lead times. VPP programs compete for the same manufacturing slots.

A 200 MW distributed battery program like Capacity*Connect is not a single purchase order. It is a multi-year, multi-category procurement pipeline that touches nearly every product line in a distribution equipment catalog.

What This Means for Procurement Teams

If you are a municipal utility or cooperative considering a VPP program: The economics work, but the pricing fracture means you are not getting the same deal as large IOUs. Explore aggregated procurement, either through your buying group (APPA, NRECA, PowerXchange) or by pooling orders with neighboring utilities. A joint 20 MW order gets better pricing than ten separate 2 MW orders.

If you are already planning a battery storage RFP: Check FEOC compliance on every product in your bid evaluation. Half the market carries high FEOC risk, and compliant products cost more. Build the compliance premium into your budget now rather than discovering it at bid evaluation.

If you serve Virginia or Minnesota utilities: Virginia utilities file grid utilization metric petitions by October 15, 2026; the metrics the SCC approves are the signal to watch for AMI, grid sensor, voltage regulator and SCADA/DMS demand. Minnesota’s 200 MW distributed buildout needs interconnection equipment, protection systems, and pad-mount transformers through 2028.

If VPPs are still a “someday” item in your planning: Define the service before pricing the equipment. Ask bidders to document dispatch duration, local network constraints, customer participation terms and the evidence behind any capacity guarantee. Compare that offer with the grid work it is meant to defer.

The weekly read on where this is heading

Minnesota and Virginia moved VPPs from a pilot conversation to an approved program and a regulatory deadline within two weeks of each other, and the bill of materials runs well past batteries. The Feeder is our free weekly digest of the procurement signals that move utility and distribution equipment buyers: lead-time shifts, supplier capacity, federal funding, and the RFP language that follows. One email a week, no filler.

Subscribe to The Feeder

Related Reading

• NFPA 800 Battery Safety Code: Procurement Impact
• The Triple Squeeze Hitting Utility Equipment in 2026
• 50 GW of Data Centers Are Rewriting Grid Procurement