6.6 Gigawatts Short at Full Price
PJM’s most recent capacity auction cleared at the price ceiling and still fell 6.6 gigawatts short of the one-in-ten-year reliability standard. The largest organized electricity market in the United States offered the maximum allowable price for generation commitments and could not secure enough.
A report published March 30 by GridLab argues that the missing capacity does not need to come from power plants.
GridLab’s four reforms for PJM states. The report, authored by Michael Lee, former CEO of Octopus Energy US, proposes a framework called “Retail 2.0” targeting deregulated electricity markets in Ohio, Pennsylvania, Maryland, and New Jersey. The mechanism is direct: competitive retail electricity providers would subsidize battery installations at customer sites, then dispatch those batteries during peak demand to earn wholesale capacity and energy revenue. Customers receive a discounted electricity rate. The grid receives distributed capacity that clears in the same auctions where gas turbines and nuclear plants compete.
Lee identifies four state-level reforms that would enable the model: mandating smart meter data for financial settlement between utilities and retail providers, requiring utilities to share low-latency granular consumption data, reforming capacity cost allocation to retail providers, and permitting retailers to issue branded customer bills. None require new technology. All fall within existing state public utility commission authority.
The report projects that both capacity and energy prices would decline for all PJM customers, not just participants, as distributed capacity additions lower auction clearing prices and peak-hour demand shifting reduces energy market costs.
Base Power’s billion-dollar proof point. The proposal is not speculative. Base Power, a Texas retail electricity provider, has deployed more than 100 megawatt-hours of battery capacity across thousands of customer homes. The customer rate: 8.5 cents per kilowatt-hour plus delivery fees. Base Power dispatches the batteries during grid peaks, captures wholesale revenue, and reinvests that revenue to subsidize hardware installations. In October 2025, the company raised $1 billion to expand beyond Texas.
It is not alone. Octopus Energy US launched a similar retail-plus-battery program in Texas in 2024. Tesla operates a retail electricity program in the same market. Three companies, three variations on one thesis: the entity that funds the battery is not the utility, not the building owner, and not a government incentive program. It is the competitive retail provider, recouping its investment through wholesale markets.
PJM’s capacity shortfall is what makes the economics work at scale. When capacity prices are low, wholesale revenue from dispatching a customer-sited battery does not justify the hardware cost. When capacity prices hit the auction ceiling and supply is still short, a battery that can reliably deliver during peak hours becomes one of the most valuable assets on the grid, regardless of where it sits.
Incentive budgets shrink in three states that pioneered them. The GridLab report arrives as the states that built the original clean energy incentive architecture dismantle it. Rhode Island Governor Dan McKee’s budget proposal caps energy efficiency program spending at $75 million annually, freezes virtual net metering credits as of July 1, 2026, and extends the state’s 100 percent renewable electricity standard deadline to 2050, with projected ratepayer savings of $1 billion over five years. Massachusetts utility regulators have ordered administrators to cut $500 million from a planned $5 billion three-year energy efficiency budget. Maine legislators from both parties have moved to lower community solar incentives.
The pattern is consistent. Ratepayer-funded surcharges that financed clean energy deployment are generating affordability backlash. Governors who championed these programs now frame them as political liabilities. E&E News characterizes the shift as a structural challenge to the “blue-state climate model” that funded deployment through utility bills, public subsidies, and emissions mandates.
Commercial electricity rates, meanwhile, are rising 7.8 percent nationally in 2026, the fastest increase across all customer sectors, driven by multi-billion-dollar transmission and distribution infrastructure programs flowing through as higher delivery charges. Each rate increase improves the standalone economics of battery storage by widening the spread between peak-period costs and off-peak charging costs. The incentive stack is contracting precisely as the underlying market economics strengthen.
Mandates and rate design replace rebates. A Morgan Lewis state policy survey published in March documents the structural replacement taking shape. Thirteen states now have binding storage procurement targets, up from 10 in 2024. Thirty-five states plus the District of Columbia have enacted frameworks enabling virtual power plant and distributed energy resource aggregation. Illinois’s Clean and Reliable Grid Act mandates time-of-use pricing from ComEd and Ameren starting June 2026, creating rate differentials that make battery arbitrage viable without any rebate program.
These are policy instruments that do not depend on annual appropriations. A TOU rate structure cannot be defunded in a budget fight. A VPP aggregation framework does not expire when a governor shifts priorities. The GridLab proposal extends this logic to its conclusion: competitive market participants should fund battery deployment themselves, using wholesale revenue that currently flows to centralized generators.
The four reforms GridLab identifies do not require legislation in Ohio, Pennsylvania, Maryland, or New Jersey. They require state commissioners willing to restructure retail electricity markets. Base Power deployed 100 megawatt-hours in Texas with a model that already works and raised a billion dollars to prove it scales. Somewhere in PJM, 6.6 gigawatts of capacity is missing. The open question is whether it arrives as power plants that take five years to permit or as batteries that a retail provider can install in months.
Sources
PJM States Could Lower Electric Bills by Enabling Retail Choice with Household Batteries (pv magazine USA)
One Casualty of Democrats’ Affordability Pivot: Climate Goals (E&E News)
Save Now, Pay Later: Critics Warn McKee’s Plan to Ease Energy Bills Comes With a Tab (Rhode Island Current)
Cuts to Rhode Island Energy Efficiency Plan Could Cost Residents (Canary Media)
State Energy Storage Policy Trends for 2026 (Morgan Lewis)
Electricity Prices, Demand to Continue Rising in 2026 (Utility Dive)