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State regulators would unlock gigawatts of flexible capacity by reforming some retail market rules that create conditions for lower pricing and ultimately cut new transmission and generation expenditures, according to a recent paper by the former U.S. CEO of Octopus Energy.

Michael Lee, in a paper published earlier this year by consultancy GridLab, said that retail markets could be transformed because of the confluence of high price volatility, lower costs for batteries, heat pumps, smart thermostats and the applications and software which connect them.

“When customers demonstrate verified behind-the-meter capacity … they require less standby central station generation,” he said.

In Lee’s proposal, termed Retail 2.0, retailers compete by co-optimizing customer load around both grid needs and consumer preferences, and through the ability to deliver long-term value.

Segments of Lee’s paper criticize the PJM Interconnection, which he says mandates that new generation wait for local utilities to complete transmission upgrades, a combined process which takes years and benefits incumbents.

PJM was criticized for poor planning when a scheduled capacity auction in December closed 6,600 MW short of its reserve margin.

The Federal Energy Regulatory Commission approved on April 28 a PJM proposal to collar capacity prices with a cap of approximately $325/MW-day and a floor of $175/MW-day for upcoming auctions for the 2028-2029 and 2029-2030 delivery years.

The collar was also applied to prior auctions for the 2026-2027 and 2027-2028 delivery years.

Lee’s plan relies on many significant regulatory changes, such as faster settlements, capacity cost allocation reforms and supplier-consolidated billing.

The paper suggests a set of end-to-end reforms of power markets, starting with the customer experience.

Retail 2.0 proposes supplier-consolidated billing that would eliminate what he calls the “hiding of exploitative bait-and-switch pricing schemes” in branded utility bills.

In Lee’s view, current retail marketing relies on a low, locked-in rate for an initial period that is automatically rolled into a variable rate that can be two to three times the introductory price.

“So much profit is realized in the first few months after the variable rate kicks in that companies systematically underinvest in long term customer satisfaction,” the paper said.

As a result, customers become skeptical of competitive offers and regulators protect consumers with rules that make it harder for new companies to enter the market.

“Utilities use these failures as evidence that retail choice does not work and should be eliminated in their quest to re-monopolize,” Lee said.

The Retail 2.0 model is based on a different pricing scheme. Retailers would gain a competitive advantage by incentivizing client consumption away from peak priced times, and providers that do not shift loads have would face financial pressure to exit the market.

To meet that objective, utilities must provide actual smart meter data for residential customer settlements within one to two days. Lee said PJM utilities now use generic load profiles for an initial settlement cycle and the actual meter data 60 days later.

In the meantime, retailers must bridge the cash flow gap between the first and second settlement cycles. This prevents verification of optimization strategies, makes iterative improvements difficult and discourages investment in sophisticated load optimization.

Retailers should be able to offer pricing that separately discloses fixed capacity costs and variable energy charges on customer bills. This would help them make informed decisions to shift consumption to low-price hours. Retailers now have to translate both into a single variable per-kWh charge.

With adequate reforms in load settlements, traditional retail energy providers will incur financial losses if they do not flex their customer loads away from high priced times, according to the paper.

Lee said that data for existing retail customers should be delivered through an application programming interface within 24 hours of usage through a platform similar to Smart Meter Texas. The platform is a collaboration of Texas utilities that stores 15-minute data.

State regulators must mandate Green Button platforms so retailers can easily size batteries for new customers. These platforms are standardized to provide utility customers access to their energy usage information.

States also should grant permits for behind-the-meter assets by right rather than requiring months-long approval processes. Competitive suppliers should be given the opportunity for same-day enrollment for customers with active utility service.

A bigger reform suggested in the paper would allow retailers to immediately purchase reduced or zero capacity tags for customers with behind-the-meter assets that shift the capacity demand curve to the left in PJM’s annual auction.

Additionally, Retail 2.0 would allow mid-year adjustments to peak load contribution (PLC) instead of the annual corrections that determine capacity payments. Lee’s scheme would create mechanisms to recognize negative PLC values when customers reduce peak load below a baseline and to pool negative PLC values, as utility ComEd does in Illinois.

Behind-the-meter asset deployment at scale depends on immediate value capture, he said. An annual PLC lock-in forces a one-year wait, making the economics of Retail 2.0 unworkable. Mid-year adjustments and negative PLC recognition transform the economics by allowing retailers to monetize grid services as they are delivered.

Another significant reform by states would be the establishment of variable transmission rates that tie customer costs to consumption during transmission system peak hours rather than flat, volumetric charges.

“The aggregated effect of thousands of customers optimizing for variable transmission rates creates a leftward shift in the transmission demand curve during peak hours,” Lee said. “States can enable behind-the-meter assets to co-optimize for transmission system peaks alongside energy, capacity and distribution signals.”

Transmission costs can represent 15% to 30% of a customer’s total bill in many regions, the paper said.

In Lee’s Retail 2.0 paradigm, a customer’s storage battery is financially encouraged to maximally export during prices that indicate the grid is stressed.

The customer’s behind-the-meter assets pre-cool or pre-heat during cheap overnight hours, increase consumption by the battery during midday solar hours and reduce demand by approximately 50% during the evening super-peak hours.

“Shifting the demand curve left by even a small amount … creates disproportionately large system-wide savings,” the paper said, using PJM data analyzed by Aurora Energy Research. “When the demand curve shifts left and intersects the supply curve at a lower price point, everyone pays that lower clearing price.”

Lee contends a lack of flexibility benefits utilities by justifying the construction of generation capacity and transmission infrastructure, expanding the utility rate base and the return on equity.

“States cannot wait five to seven years for new central station generation to clear the

interconnection queue,” he said. “One hundred megawatts of capacity can be assembled from 1,500 homes with battery systems, deployed across a metropolitan area in a matter of months.”

Lee’s Retail 2.0 model ultimately foresees utilities becoming distribution system operators, or DSOs, running real-time markets that pay specific customers on constrained parts of the grid to provide stability.

When a distribution feeder hits capacity limits, the DSO runs a locational flexibility market where retailers bid behind-the-meter capacity to resolve the constraint.

“The battery owner on the constrained feeder gets paid to discharge during peaks. The electric vehicle owner delays charging,” the paper said. “Market coordination delivers reliability at a fraction of traditional infrastructure costs.”