The DER aggregation landscape at the start of 2026 looks materially different from where it stood when FERC Order 2222 was issued in 2020. ISO compliance tariffs that were abstract regulatory text five years ago are now operational market rules. The first generation of community solar programs that pursued Order 2222 pathways have cleared capacity auctions and are generating delivery year capacity revenue. Case law from FERC's ongoing oversight of ISO compliance tariff implementation has started to clarify the boundaries of acceptable DER aggregation registration practices. And community solar program developers who spent 2021-2023 watching from the sidelines are now asking serious questions about ISO capacity market enrollment timelines.
This is our perspective on where the DER aggregation market is heading in 2026 — the developments that matter, the areas where we see continued friction, and what community solar operators should be watching.
ISO Compliance Tariffs: From Filing to Operations
The most significant shift in 2025-2026 is the transition from ISO tariff compliance filings being primarily a regulatory and legal exercise to being an operational reality. PJM's DER aggregation participation model has processed its first cohort of aggregation registrations through the full enrollment cycle. ISO-NE's DER aggregation provisions are generating their first FCM qualification attempts. NYISO's DRIS-based pathway for Order 2222 compliance has handled a growing number of aggregation enrollments.
What the operational experience has revealed: the tariff provisions that looked workable on paper have predictable friction points in execution. EDC notification response times vary more than the tariff provisions anticipated. Telemetry testing queue times at both PJM and ISO-NE are longer than the regulatory drafters expected, partly because the ISOs are scaling testing capacity in response to actual enrollment demand rather than forecast demand. Distribution constraint identification — the process by which EDCs flag potential issues with BTM dispatch — is handled more thoughtfully by some utilities than others, and the variance creates enrollment timeline uncertainty that is difficult to predict from the ISO tariff language alone.
None of these friction points are fatal to the Order 2222 pathway. They're operational realities that programs need to plan for. The programs that entered 2025 with conservative 12-14 month enrollment timelines mostly made it through to auction enrollment. The programs that planned for 6-8 months based on what the tariff provisions technically require largely did not.
ELCC Methodology Evolution
PJM's continued evolution of the ELCC (Effective Load Carrying Capability) methodology for intermittent and hybrid resources is one of the most consequential ongoing technical developments for community solar DER aggregators. PJM has been updating its ELCC studies to better reflect the reliability contribution of solar resources given increasing solar penetration — a development that, in general, tends to reduce the ELCC value attributed to additional incremental solar capacity as the system's coincident peak periods shift.
For community solar programs planning capacity commitments in 2027/2028 delivery year auctions, the ELCC value used for commitment sizing should reflect PJM's current methodology rather than historical ELCC values from earlier study years. Programs that used 2022 ELCC factors as the basis for their 2025 capacity models may find their capacity revenue projections overstated when PJM applies updated ELCC values to the aggregation's capacity credit. The mismatch between outdated ELCC assumptions and current ELCC values is a source of commitment sizing error that deserves explicit attention in program financial models.
ISO-NE has been on a similar trajectory with its capacity credit methodologies for intermittent resources. The FCM's treatment of solar capacity credit has evolved through successive capacity market design proceedings, and programs entering the FCM for the first time in 2026 should work from the current FCM capacity credit calculation, not from descriptions of the methodology in older industry analyses.
Battery Storage Paired with Community Solar: The Growth Trajectory
One of the clearer trends in 2025-2026 is the accelerating rate at which community solar programs are pairing battery storage with subscriber solar portfolios. The economics have shifted: battery storage costs have come down substantially over the 2020-2024 period, state incentive programs (particularly IRA-derived incentives for storage paired with solar) have improved the installed economics, and community solar program developers have recognized that storage-paired portfolios have materially stronger ISO capacity market credentials than solar-only portfolios.
The capacity market advantage of solar + storage over solar-only is real but often overstated in program pitches. The storage component adds dispatchability — the ability to respond to dispatch instructions after sunset or under cloud cover when solar is unavailable — but the incremental capacity value depends on the storage duration relative to the ISO's dispatch requirements and the existing SOC at dispatch time. A 2-hour battery that's 50% discharged from afternoon self-consumption optimization has less incremental capacity contribution than the nameplate numbers suggest. Proper co-optimization of the storage dispatch for capacity market performance remains the technical challenge that the market hasn't fully solved at scale.
Community Solar Program Developers Entering the Market Seriously
Perhaps the most significant market development heading into 2026 is the shift in how community solar program developers think about ISO capacity markets — from "something we'll look at eventually" to "a competitive program differentiator we need to have a position on in the next 18 months."
This shift is driven by a few converging factors. The SREC markets in several states have matured to lower value levels as solar penetration grows, reducing the non-capacity revenue stack that programs previously relied on to underwrite program economics. Grid reliability concerns in PJM and ISO-NE have sustained higher capacity clearing prices than the markets saw in the 2018-2020 period, making capacity revenue more attractive relative to the enrollment cost and complexity. And the first cohort of programs that completed ISO enrollment have started producing data on actual capacity market revenue per MW, creating a more concrete ROI case for programs evaluating the pathway.
We're not saying that every community solar program should be targeting ISO capacity market participation. Programs with very small portfolios (below ISO minimum aggregation thresholds), programs in development stages with uncertain ISO enrollment timelines, and programs in states without clear community solar regulatory frameworks face genuine obstacles that may defer the capacity market opportunity. The honest assessment is that the capacity market pathway is realistic and economically attractive for programs above roughly 10-15 MW with stable subscriber enrollment and a clear path to the relevant ISO territory's enrollment threshold — and it's not yet the right priority for programs well below that threshold.
FERC Regulatory Watch: What's in the Pipeline
Several FERC proceedings are relevant to DER aggregators watching the 2026 regulatory landscape:
FERC's ongoing monitoring of ISO Order 2222 compliance tariff implementation has generated a series of compliance filings and deficiency orders in 2024-2025, particularly around the distribution-wholesale interface provisions. ISOs that have been slow to implement EDC coordination processes consistent with the order's intent have faced FERC pressure to remedy the deficiencies. The resolution of these proceedings will matter for aggregators in territories where EDC coordination has been a friction point.
FERC's consideration of compensation for distributed energy resources in energy markets — building on Order 2222's capacity market provisions — represents a potential second phase of revenue opportunity for BTM portfolios that complete capacity market enrollment. Energy market and ancillary services participation for DER aggregations is technically more demanding than capacity market participation, but the regulatory framework is moving in the direction of enabling it.
What 2026 Looks Like on the Ground
For a community solar operator entering 2026 with a 15-20 MW BTM portfolio in PJM territory and a serious interest in ISO capacity market participation, the practical outlook is: enrollment timelines have stabilized in the 9-14 month range for well-prepared programs; the documentation and telemetry requirements are well-understood from the first cohort's experience; and the capacity market revenue opportunity at current PJM clearing price levels is large enough relative to program size to justify the enrollment investment.
The programs that will capture capacity market revenue in the 2027/2028 delivery year are the ones beginning their enrollment preparation now — not in mid-2026 when the enrollment window is closing. The programs that will regret waiting are the ones watching PJM capacity clearing prices from the outside and treating the enrollment process as something to start when the program feels "ready." Programs are never fully ready; they reach a threshold of readiness where the enrollment timeline becomes viable, and that threshold arrives earlier than most operators anticipate when they're looking at the full enrollment checklist for the first time.
The DER aggregation market in 2026 is mature enough to be navigable and early enough that meaningful market position is still available to programs that start preparing seriously this year.