FERC Interconnection Reform 2026: EPC Guide

Last updated August 22, 2026 (Originally published July 25, 2026)

Quick Answer

Why This Matters for EPCs

If your pipeline touches PJM, plan around an eight-year reality, not a three-year-old reform's on-paper promise. And if you're pitching solar-plus-storage to serve a data center or other large load directly, a live, unresolved cost-allocation question just opened at FERC in June 2026, one that could materially change who pays for the network upgrades your project triggers. These are two separate stories moving at two different speeds, worth understanding as distinct rather than one general "interconnection is slow" narrative.

Where Interconnection Reform Actually Stands

FERC Order 2023, issued in July 2023, replaced the old "first-come, first-served" serial interconnection process with a "first-ready, first-served" cluster study model, requiring transmission providers to study groups of projects together rather than one at a time, and imposing financial penalties for missed study deadlines. It also established co-location standards allowing battery storage to share a single interconnection request with a generation asset, addressing a longstanding barrier for hybrid solar-plus-storage projects.

That was three years ago. The reform is still being implemented, unevenly, and it hasn't yet reversed the underlying trend: PJM's own data shows the average time from interconnection application to commercial operation rose from under two years in 2008 to more than eight years in 2025.

The Cluster Study Timeline: What Order 2023 Promises vs What's Actually Happening

Order 2023's cluster study process has a defined timeline on paper:

Add the phases together and the reform's own design targets roughly 315 days, about 10 and a half months, from the close of the customer request window to a signed interconnection agreement, before the separate facilities study that follows.

PJM's actual average, cited earlier in this piece, is running over eight years. That's not a modest miss. It's the reformed process taking nearly ten times longer than its own design target, which points to the bottleneck being sheer project volume competing for limited interconnection points, plus the ongoing compliance friction between FERC and PJM, rather than a flaw in the cluster study framework itself.

Transmission providers also face real financial penalties for missing these deadlines: $1,000 per business day for a late cluster study, $2,000 per business day for a late cluster restudy, each capped at 100% of the study deposits collected. Those study deposits themselves run $55,000 to $250,000 per project, collected once at interconnection request submission. For an EPC setting client expectations, both the deposit size and the theoretical timeline are worth stating separately from whatever a specific RTO's actual track record looks like.

Why PJM Is the Center of This Story

PJM is the largest RTO in the country, serving more than 65 million people across 13 states and Washington, D.C., and it's also the region where Order 2023 compliance has run into the most trouble. In July 2025, FERC rejected PJM's Order 2023 compliance plan as insufficient, finding that while parts of PJM's process complied, PJM had not met the rule's full requirements. In April 2026, FERC accepted PJM's revised compliance filing "in part" and directed further compliance filings, an ongoing, unresolved process as of this update.

Two additional PJM-specific developments EPCs should track:

• Co-located generation and load. In December 2025, FERC found PJM's tariff "unjust and unreasonable" for lacking clear rules on co-located generation and load arrangements (relevant to solar-plus-storage projects serving large loads like data centers), and ordered PJM to file revised interconnection procedures by January 20, 2026 and co-location terms by February 16, 2026.
• PJM's Transition Cycles and Cycle 01. PJM is clearing its pre-2023 legacy backlog through two Transition Cycles, separate from the new go-forward annual process. Transition Cycle 1 completed its studies in September 2025 and finalized interconnection agreements by April 27, 2026, adding 17.4 GW, including 21 battery storage projects totaling 1.9 GW. Transition Cycle 2, the larger remaining piece at roughly 46 GW, entered Phase III on July 8, 2026, and PJM expects to finalize agreements in the first quarter of 2027. Separately, Cycle 01, the first cycle of PJM's new permanent, annual-intake process, closed its application window April 27, 2026 with 715 projects and more than 200 GW qualified for study, with a one-to-two-year processing time going forward. These are three distinct tracks, don't assume a client's project timeline based on one without checking which track it's actually in.

FERC's Second Track: Show-Cause Orders for Data Centers and Large Loads

Everything above describes FERC's generation-side reform, Order 2023, the cluster study process, PJM's compliance struggles. In 2026, FERC opened a second, separate reform track for the other side of interconnection, large loads, specifically data centers and other facilities drawing more than 20 megawatts. It's moving at a completely different speed.

The origin: on October 23, 2025, DOE Secretary Chris Wright invoked Section 403 of the DOE Organization Act, a rarely used statutory authority that compels FERC to act, and directed the Commission to fix large-load interconnection. FERC committed to acting by the end of June 2026.

It delivered. On June 18, 2026, FERC issued six separate Section 206 show cause orders, one to each RTO it regulates: PJM, MISO, SPP, CAISO, ISO-NE, and NYISO. Each order requires that RTO to demonstrate its existing large-load interconnection tariff is just and reasonable, or propose fixes. FERC defined a large load as a facility with peak demand exceeding 50 MW that interconnects at transmission voltage above 69 kV, a narrower and more specific threshold than the 20 MW figure DOE originally proposed in its October 2025 directive. Notably, FERC chose not to issue a single nationwide rule. Six targeted, region-specific orders instead, a deliberate choice, more legally durable against state-level jurisdictional challenges than a broad rulemaking would be.

Each RTO has 60 days from June 18 to respond, by August 17, 2026, unless it requested a 90-day abeyance by August 3, 2026 to pursue a stakeholder-driven Section 205 filing instead. As of this writing, which of the six RTOs met the August 17 deadline directly versus requested that abeyance hasn't been independently confirmed here, worth checking each RTO's own docket directly if the answer matters for a specific project.

A separate, faster 30-day deadline required each RTO to file a generation-adequacy report addressing whether it can actually supply enough power for new and existing large loads, that deadline was July 20, 2026, already passed.

FERC named five specific issues each RTO's response has to address: efficient application and study processes, including consideration of alternative transmission technologies; preventing cost shifts onto other ratepayers and improving transparency into large-load-driven transmission costs; and a defined study process for facilities that are electrically proximate to or co-located with large loads.

That cost-allocation direction is worth stating plainly to a client: the underlying DOE framework recommended assigning 100% of network upgrade costs triggered by a large load onto the load itself, not spreading it across the general ratepayer base the way generation interconnection costs sometimes are. If you're structuring a solar-plus-storage project intended to serve a data center directly, this cost allocation question is now a live, actively-being-decided policy matter, not settled.

FERC is also encouraging RTOs to adopt pro forma agreements requiring large-load customers to make a minimum financial commitment backstopping network upgrade costs if the load doesn't materialize as planned or takes less service than contracted for. In effect, this shifts stranded-cost risk onto the large-load customer rather than other ratepayers, a real increase in financial exposure for any project structured around serving a data center or similar large load.

FERC specifically credited two RTOs for prior progress: SPP for its High Impact Large Load framework, approved January 14, 2026, which delivers interconnection agreements within 90 days for qualifying large-load projects, and PJM for its own large-load and co-location work already underway, described above. Every other RTO is starting further behind.

One outside region worth noting: the Pacific Northwest isn't under FERC jurisdiction for this purpose, no RTO or ISO covers it, but Bonneville Power Administration is running its own reform effort, the Grid Access Transformation Project, and is likely to model changes on whatever the six FERC-jurisdictional RTOs land on.

The Real Cost of Delay, Not Just the Inconvenience

This isn't just a scheduling headache. Analysis commissioned by GridLab and conducted by Aurora Energy Research found that if just 10% of the 107 GW of land-based renewables sitting in PJM's pre-2024 queue had been built in time for the 2026-2027 capacity auction, it would have added 1.5 GW of net supply and saved PJM consumers approximately $3.5 billion. That auction ultimately hit the FERC-imposed price cap of $329 per MW-day across PJM's entire footprint, direct evidence of the supply pressure slow interconnection is creating.

This Isn't Going Unchallenged

The reform process itself is contested from multiple directions, worth knowing before presenting Order 2023 to a client as a settled fix. American Electric Power filed a formal petition with FERC requesting an extended compliance deadline, and specifically flagged concern with the new penalty regime: AEP's vice president for FERC and RTO strategy called the elimination of the prior "Reasonable Effort Standard" and the imposition of financial penalties "very fraught," warning it could generate litigation and further delay rather than speed up interconnection. Separately, environmental law group Earthjustice filed a formal protest against PJM's own compliance filing, arguing PJM's plan only "anticipates" clearing its backlog by 2026 without offering any binding commitment or clear evidence it will hit that timeline.

The practical read: don't present PJM's reformed process to a client as a fixed problem. It's a process still being actively litigated and challenged by parties on both sides, utilities arguing the penalties go too far, advocacy groups arguing PJM's plan doesn't go far enough.

Why 2026 Looks Different by State, Not Just by RTO

SEIA's own Q2 2026 market outlook adds a layer of regional detail worth factoring into procurement planning specifically. The report projects a near-term national contraction in 2026, driven primarily by California's transition to a new tariff regime, with New York and Massachusetts also expected to install less new commercial solar this year specifically because of lengthy interconnection delays and reduced pipeline volumes in those states. That's a useful, concrete example of how the national interconnection story translates into state-specific procurement risk: an EPC with projects concentrated in these three states should expect 2026 to look meaningfully different than the national picture suggests, and should factor that into client timeline conversations now rather than after a project stalls.

It's Not Just PJM

Every major grid operator is dealing with a version of this problem, though the specifics vary:

Nationally, the interconnection backlog stands at roughly 2,200 GW, and 111 GW of hybrid solar-plus-storage capacity was added to queues in the past year alone, according to S&P Global Commodity Insights.

Common Mistakes to Avoid

• Presenting Order 2023 to a client as a solved problem. It's still being actively implemented, litigated, and contested by parties on multiple sides.
• Quoting the 315-day theoretical cluster study timeline as what a client should expect. It's the design target, not the observed reality, PJM's actual average is nearly ten times longer.
• Treating FERC's data center show-cause orders as the same process as Order 2023. They're separate reform tracks, moving at different speeds, addressing different sides of interconnection.
• Assuming ERCOT's overall speed advantage extends to battery storage right now. BESS applications there fell 50% in the second half of 2025, a policy-driven pullback, not a process failure.
• Assuming a state with a fast RTO process is immune to the state-specific headwinds SEIA flagged for 2026. California, New York, and Massachusetts all face contraction this year for reasons beyond the federal reform picture.

What EPCs Should Actually Do With This Information

• Treat interconnection timeline as a separate critical path from construction, not a formality that runs in parallel.
• Check your specific RTO/ISO's current compliance status, not just the fact that Order 2023 exists nationally.
• For solar-plus-storage projects in PJM specifically, watch the co-location rule developments closely.
• Build realistic client expectations around the 8-year PJM average, not the pre-reform 2-year baseline, or the reform's own 315-day design target.
• Don't assume ERCOT's speed advantage extends to storage right now.
• If you're pitching a project to serve a data center or other large load, track whether that project's RTO has filed its response to FERC's June 18 show-cause order, and flag the open cost-allocation question directly in the client conversation rather than assuming today's cost-sharing rules will hold.

How This Fits Into a Reslink Workflow

For any project in PJM, budget planning around the actual 8-year average, not the reformed process's 315-day design target, and separately track whether your project's RTO has responded to FERC's June 18 show-cause order if it involves a large-load or data-center-adjacent interconnection. For solar-plus-storage projects being pitched to serve a data center or other large load directly, flag the live cost-allocation question, whether network upgrade costs land on the load or get socialized, as a real, unresolved variable in the financial model, not a settled assumption.

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Frequently Asked Questions

Q1. How long does grid interconnection actually take right now?

It varies significantly by region, but PJM's own data shows the average time from application to commercial operation has risen from under two years in 2008 to more than eight years in 2025. This is despite FERC Order 2023 reforms that took effect starting in 2023.

Q2. Has FERC's Order 2023 reform actually fixed the interconnection backlog?

Not yet, and not uniformly. The national interconnection backlog stands at approximately 2,200 GW. FERC itself rejected PJM's Order 2023 compliance plan as insufficient in July 2025 and only partially accepted a revised version in April 2026, with further compliance filings still required.

Q3. Does interconnection reform include battery storage and co-located systems?

Yes, in part. Order 2023 established co-location standards letting battery storage share a single interconnection request with a co-located generation asset. In PJM specifically, FERC ordered further rule clarity in December 2025 for co-located generation serving large loads, with compliance filings due in January and February 2026.

Q4. Why did ERCOT battery storage applications drop in 2025 if ERCOT has the fastest interconnection process?

ERCOT operates outside FERC jurisdiction and remains the fastest interconnection process in the country, but BESS applications there fell roughly 50% in the second half of 2025 compared to the first half, driven by policy uncertainty, including the loss of key federal tax credits, not by process delays.

Q5. What's the practical impact of interconnection delays on project economics?

Significant. Analysis for PJM specifically found that building just 10% of the land-based renewables stuck in its pre-2024 queue in time for a recent capacity auction would have saved consumers an estimated $3.5 billion and added meaningful supply. That auction instead hit the FERC price cap, direct evidence of the cost of delay.

Q6. Is FERC's interconnection reform actually settled, or still being contested?

Still being contested, from both directions. American Electric Power petitioned FERC for an extended compliance deadline, warning the new penalty system could trigger litigation. Earthjustice separately filed a formal protest against PJM's compliance plan, arguing it lacks a binding commitment to clear its backlog on the timeline PJM claims. Treat this as an active, unresolved process, not a finished reform.

Q7. Which states are expected to see reduced solar installation in 2026 specifically because of interconnection issues?

SEIA's Q2 2026 market outlook specifically flags New York and Massachusetts, alongside California's separate tariff transition, as drivers of a projected national contraction this year. EPCs with projects concentrated in these states should plan for longer timelines than the national average implies.

Q8. What are FERC's June 2026 show-cause orders on data center interconnection?

On June 18, 2026, FERC issued separate orders to each of the six RTOs it regulates, PJM, MISO, SPP, CAISO, ISO-NE, and NYISO, directing each to justify why its current tariff adequately handles large-load interconnection, defined as facilities drawing more than 20 megawatts, primarily data centers, or propose fixes. Each RTO has 60 days to respond, with compliance filings due in mid-August 2026. This follows an October 2025 directive from DOE Secretary Chris Wright compelling FERC to act.

Q9. How is the data center interconnection reform different from Order 2023?

Order 2023 reforms how generation projects, solar, wind, storage, connect to the grid, and it's been in effect since 2023 with mixed, still-struggling results. The 2026 show-cause orders address the opposite side, how large loads like data centers connect. It's a separate, newer, faster-moving process. SPP's comparable large-load framework already delivers interconnection agreements within 90 days for qualifying projects, a sign of what this reform track is aiming for, versus Order 2023's multi-year real-world struggles on the generation side.

Q10. What is PJM's Transition Cycle 2, and when will it be done?

Transition Cycle 2 is the second and larger phase of PJM clearing its pre-2023 legacy interconnection backlog, roughly 46 GW of projects. It entered Phase III on July 8, 2026, and PJM expects to finalize interconnection agreements in the first quarter of 2027. It's separate from Cycle 01, the first cycle of PJM's new permanent annual process for new applications going forward, which closed its application window in April 2026 with over 200 GW under study.

Sources

• FERC, Explainer on the Interconnection Final Rule (ferc.gov) – confirms Order 2023's cluster-study framework, compliance deadlines, and Order 2023-A rehearing details.
• Utility Dive, "FERC orders changes to PJM's grid interconnection process" – confirms the July 2025 rejection of PJM's Order 2023 compliance plan and the 63,000 MW 2026 review target.
• FERC, April 2026 Commission Meeting Summaries (ferc.gov) – confirms the April 2026 order accepting PJM's compliance "in part" and directing further filings.
• K&L Gates, "FERC Orders PJM to Reform Tariff for Co-Located Generation and Load" – confirms the December 2025 co-location order and the January 20 and February 17, 2026 compliance filing deadlines.
• Energy Tech News, "FERC Interconnection Reforms Progress While Storage Queue Backlog Persists Into 2026" – confirms the 8-year PJM timeline figure, the GridLab/Aurora Energy Research $3.5 billion analysis, and MISO/NYISO/ERCOT regional data.
• Lawrence Berkeley National Laboratory, "Queued Up: 2026 Edition" (emp.lbl.gov/queues) – confirms the national 2,200 GW interconnection backlog and queue composition data.
• FERC (Primary): ferc.gov, "FERC Launches Aggressive Targeted Action to Speed Large Load Integration," June 18, 2026, confirms the six Section 206 show-cause orders, the 60-day and 30-day deadlines, and FERC's crediting of SPP and PJM for prior progress
• White & Case LLP: whitecase.com, confirms the five specific issues each RTO must address and the origin in DOE's October 2025 Section 403 directive
• Troutman Pepper Locke: troutman.com, confirms Order 2023's cluster study timeline structure, the 45-day request window, 60-day engagement window, 150-day study deadline, and penalty structure
• PJM Inside Lines: insidelines.pjm.com, confirms Transition Cycle 1 completion (September 2025 studies, April 27, 2026 agreements, 17.4 GW), Transition Cycle 2 status, and Cycle 01's 715-project, 200+ GW application window
• Zero Emission Grid: zeroemissiongrid.com, confirms Transition Cycle 2 entering Phase III on July 8, 2026 and the Q1 2027 completion target