This is the fourth and final post in our four-part “BAAJA Blast” series covering the proposed Bipartisan American Affordability and Jobs Act of 2026, released on September 30, 2026. Check out our earlier posts on the bill’s provisions on transmission, offshore wind, and data centers and large loads.

A note on timing. We close out this series in a very different political climate than the one in which we began it. This week’s midterm elections, which handed Democrats control of both congressional chambers starting in January 2027, have called this legislation’s future into  question. Will BAAJA disappear into the ether during the lame-duck session? We can’t say for sure. Some House Democrats, including the member in line to chair the House Natural Resources Committee, argue that Democrats could write a better bill next Congress; the bill’s sponsors and major industry groups, on the other hand, are pushing to finish the job this year, and the November 9 Senate cloture vote should be the first real test of whether they can. Come what may, we close out our BAAJA Blast series today with our observations on the bill’s treatment of DERs and VPPs.

On September 30, 2026, Senate negotiators released the text of the proposed Bipartisan American Affordability and Jobs Act of 2026 (“BAAJA”). For distributed energy resources (“DERs”) and virtual power plants (“VPPs”), the bill comes at a critical moment. Aggregators (which we call “VPP providers” here) increasingly bundle behind-the-meter resources—which continue to proliferate year-over-year—into VPPs that sell services back to the grid. Yet six years after the Federal Energy Regulatory Commission (“FERC”) issued Order No. 2222, several grid operators have yet to fully comply, and VPPs have begun striking deals directly with buyers.

As we have written before, AI-driven load growth is creating immense pressure to activate the demand side of the grid, and deploying VPPs is among the fastest ways to unlock new capacity. If enacted, BAAJA would replace the tariff-by-tariff process under Order No. 2222 with a statutory deadline: Section 2108 would require grid operators to admit qualifying aggregations into their wholesale markets within 18 months, limit utility interference, bar double payment, and fund a voluntary program to streamline local permitting for rooftop solar, batteries, and EV chargers. In our view, Section 2108 would likely get aggregations through the market door faster than Order No. 2222 has; whether it makes operating VPPs in the wholesale markets a durable business, however, would depend on questions the bill leaves to grid operators and states.

Our data center post previewed Section 2108’s basic market-access rule. In this post, we take a closer look at the provision as a whole, even as we note that the bill itself still faces significant hurdles. A Senate cloture vote on the motion to proceed is expected as early as November 9; passage would require 60 votes, and any Senate bill would have to be reconciled with the House’s permitting legislation before the 119th Congress ends in January 2027. A promised manager’s amendment could change the text. And again, with this week’s midterm elections turning control over Congress to the Democrats come January 2027, the fate of the bill is even less certain.

What Counts as a DER Under BAAJA

DERs are small generation, storage, or load-management assets on the distribution system, such as rooftop solar, batteries, EV chargers, and smart thermostats. A VPP is a group of DERs that a VPP provider controls through software to act like a single power plant.

Industry observers will be familiar with both these concepts; BAAJA, however, uses neither term. Section 2108, titled “Dispatchable energy systems market access,” instead defines a “qualifying behind-the-meter distributed energy system facility” (a “qualifying BTM DES facility”). The facility must be an energy storage system, fuel cell, generator, or “other resource” that can be brought online within 15 minutes and whose output the grid operator can dispatch on signal. It must sit behind a retail customer’s meter, have a rated capacity of at least 5 kilowatts, and have metering and telemetry sufficient to dispatch and settle it. That equipment need not be owned or installed by the utility and may include device-level equipment such as inverters. A “qualifying BTM DES aggregation” is two or more such facilities with a combined capacity of at least 100 kilowatts.

Wholesale Market Access (New FPA Section 229)

Section 2108 would add a new Section 229 to the Federal Power Act, the foundational statute establishing federal jurisdiction over interstate transmission and wholesale power sales. Beginning 18 months after enactment, it would not be “just and reasonable” (the legal standard FERC uses to evaluate the legality of jurisdictional rates) for any Regional Transmission Organization (“RTO”) or Independent System Operator (“ISO”) to maintain rules that prevent a qualifying aggregation from participating in its energy, capacity, or ancillary services markets.

The bill would also declare three specific practices unjust and unreasonable: imposing metering, telemetry, or equipment requirements beyond the statutory definitions; requiring participation in the energy market as a precondition to participation in the capacity market; and requiring a facility to participate jointly with a co-located resource in order to join an aggregation. Each RTO and ISO would have to file compliant market rules within 180 days of enactment, and FERC would have 180 days to approve them or impose changes. FERC would also have to act on complaints alleging noncompliance within 180 days.

Section 2108 is best understood as a legislative fix for Order No. 2222, under which three barriers have persisted: costly metering requirements, unclear rules for resources earning revenue in both state programs and wholesale markets, and distribution utilities’ control over interconnection. Section 2108 would address each directly, though it reaches only behind-the-meter resources, and its fixed deadline would leave far less room for grid operator stakeholder-process delay.

Dual Participation, Not Double Payment

Many DERs already earn money from state programs, such as net metering or a utility demand response program. Section 2108 would let them keep doing so: participation in a state program would not disqualify a facility from wholesale markets, and nothing would require a facility to enter wholesale markets at all. What the bill would bar is “double compensation,” meaning payment from both a wholesale market and a state program for the same service in the same time interval.

Within 180 days, each RTO and ISO would have to file settlement rules that exclude, service by service, any quantity already compensated under a state program. The bill’s own example illustrates the approach: a battery that earns retail credit for energy, but not for capacity or ancillary services, could still earn wholesale capacity and ancillary services revenue, just not wholesale energy revenue. Distribution utilities would have to supply the interval metering and program-participation data needed to make this work, subject to state customer-privacy protections.

VPP providers would carry much of the compliance burden. Each would have to certify which state programs paid each facility and that no double compensation was retained, and those certifications would be treated as statements to FERC for enforcement purposes. FERC would have to order disgorgement of any double compensation and, if it was knowingly retained, could impose penalties of up to three times the amount per day and suspend or terminate participation. Participants would also file public annual reports, due each March 30.

Distribution Utility Obligations (New FPA Section 230)

Section 2108 would also add a new Section 230 targeting distribution-level obstacles that have kept DERs out of wholesale markets. Within an RTO or ISO footprint, distribution utilities would have to interconnect wholesale-eligible behind-the-meter resources in a timely way, allow them to export, accept the same metering and telemetry data the wholesale market uses, and not use their control of the distribution system or retail sales to block or unreasonably condition market participation. Actions reasonably necessary for safety and reliability would remain permitted. FERC would enforce these obligations and would have to act on complaints within 180 days.

The provision includes significant limits. The interconnection obligation would yield to state law, and FERC would gain no authority over distribution-level interconnection rates or terms. State regulators would decide how wholesale metering data adjusts retail bills. For public power utilities and certain cooperatives, the requirements would be voluntary unless state law requires them. And qualifying a facility would not, by itself, bring it or its retail or distribution service under FERC jurisdiction. In practice, the utility obligations would operate more as a federal default than a guarantee.

• State regulators would be in the driver’s seat. Because the utility obligations yield to state law, state commissions, such as the New York Public Service Commission for NYISO-area resources, would largely determine how much of the distribution-side benefit reaches aggregations. We expect the provision to work best in states already pushing VPP policy, where the federal default would reinforce existing direction, and least in states whose utilities have resisted aggregation. Developers should track state proceedings as closely as FERC compliance filings.
• Data access. VPPs depend on utility distribution data to verify performance and get paid in full. The bill’s data-sharing requirement would help, but it is among the provisions most likely to be honored in form and slow-walked in practice, and its effectiveness would depend on grid operator formats and schedules, state privacy rules, and how quickly FERC acts on complaints.

Beyond Market Access: Local Permitting and Storage

Most rooftop solar, building batteries, and campus microgrids need only local permits, so the bill’s federal environmental review reforms would largely bypass them. Section 2108(e) instead would have the Department of Energy (“DOE”) stand up, within 180 days, a program supporting voluntary, streamlined local permitting and inspection for solar, batteries of at least 2 kilowatt-hours, EV chargers of at least 2 kilowatts, and hydrogen refueling, including an expanded online platform, technical assistance, and possible certification and prizes for participating jurisdictions. The bill would authorize $20 million per year for fiscal years 2026 through 2031.

Other provisions would ease siting for storage. Adding energy storage at or near an existing transmission or distribution facility would be categorically excluded from review under the National Environmental Policy Act (“NEPA”) and Section 106 of the National Historic Preservation Act, as would reconductoring, which we discussed in our transmission post. The Departments of the Interior and Agriculture would also have to adopt categorical exclusions for batteries on previously disturbed land and for small solar installations on federal property.

Looking Ahead

For VPP providers and device makers, Section 2108 would offer guaranteed RTO and ISO market access, fewer utility equipment requirements, and a firm deadline, along with real compliance obligations. Building owners could gain a new revenue stream from dispatchable equipment. Utilities would take on new interconnection and data-sharing duties, tempered by state authority. Customers outside RTO and ISO regions, including much of the Southeast and West, would see less direct benefit. An open question is whether the provision ultimately favors storage paired with clean generation or opens a new path for behind-the-meter gas.

So, would it work? We think that, if enacted, Section 2108 would deliver on market access: the deadline would be firm, the standard would be self-executing, and the prohibited practices target the barriers that have stalled Order No. 2222.

It is less likely, on its own, to make VPPs a mainstream grid resource. That outcome would depend on capacity accreditation, on how states use their room to displace the utility obligations, and on whether the dispatchability test is read to include flexible load. Aggregators, device makers, and building owners should expect compliance filings, accreditation proceedings, and state dockets to be where the practical value of Section 2108 is decided, and should plan their engagement accordingly.

This concludes our BAAJA Blast series; thank you for following along. We will continue to track the bill’s progress and its implications for developers, investors, and other market participants.