FERC Order 2023 Compliance in 2026: Why This Is the Year to Invest in Site Control Tracking

The three-year fuse that just ran out

If you've been developing solar or wind projects through the interconnection queue over the last decade, you remember the old process. File your request. Wait. Get a study. Wait more. Somewhere along the way, assemble enough lease agreements to keep your interconnection application alive. The bar for "enough" was vague, enforcement was inconsistent, and a well-timed phone call to the RTO could buy you another six months.

That era is over.

FERC Order 2023, issued unanimously in July 2023, replaced the serial "first-come, first-served" queue with a cluster-based study process that demands commercial readiness at every stage. Site control is no longer a soft expectation — it's a binary gate. You prove it or you're out.

But Order 2023 didn't hit all at once. It rolled out in phases:

• 2023: FERC issues the rule. RTOs begin drafting compliance filings.
• 2024: Compliance filings accepted (most effective January 1, 2024; CAISO effective June 12, 2024). Transition queues begin processing legacy projects under new rules.
• 2025: First reformed cluster studies complete. PJM finishes Transition Cycle 1 in November — 130 projects, 17.4 GW. FERC rules on compliance filings, directing further revisions from every RTO.
• 2026: Every RTO is running reformed processes simultaneously. PJM Cycle 1 applications open April 27. CAISO Cluster 16 opens October 1. MISO DPP-2025 Phase 1 launched January 6. ISO-NE accepts requests again October 5. The parallel enforcement window is here.

For three years, developers could argue they were still in a "transition period." That argument no longer holds. The transition is over. The new process is the process.

What the numbers say about the old way of doing things

The Lawrence Berkeley National Laboratory's Queued Up 2025 report — the most comprehensive analysis of U.S. interconnection queues — puts the scale of the problem in sharp relief:

• ~10,300 projects actively seeking grid interconnection, representing 1,400 GW of generation plus ~890 GW of storage.
• Only 13% of capacity that submitted interconnection requests from 2000–2019 reached commercial operations by end of 2024.
• 77% of that capacity withdrew. Not failed — withdrew. Projects that entered the queue, consumed study resources, delayed other developers, and then walked away.
• Median time from interconnection request to commercial operation doubled from under 2 years (2000–2007) to over 4 years (2018–2024).

FERC Order 2023 was designed to fix this. The readiness requirements — escalating deposits, site control verification, withdrawal penalties — are specifically engineered to force the 77% withdrawal rate even higher and earlier, so that the projects remaining in the queue are real.

The first evidence that this is working: total active queue volume decreased 12% year-over-year in 2024, the first decline in at least a decade. The speculative projects are being flushed.

The financial stakes have fundamentally changed

Under the old process, the cost of poor site control documentation was delay. Under Order 2023, the cost is capital destruction.

Here's the deposit escalation ladder every developer now faces:

Source: FERC Order 2023 Explainer and Troutman Pepper analysis.

For a 200 MW solar project with $50M in assigned network upgrades, that 20% LGIA deposit is $10 million. An expired option that drops your coverage below threshold at facilities study doesn't just mean a stern letter from the RTO — it means forfeiting a seven-figure deposit and losing years of development work.

The LBNL interconnection cost database shows average interconnection costs of $167/kW for solar and $138/kW for wind. For projects that withdrew from PJM between 2020–2022, the mean cost was $599/kW — more than 3.5x higher than projects that completed. The lesson: failing late costs exponentially more than failing early, and Order 2023's deposit structure ensures that late failures are ruinously expensive.

Where each RTO stands right now

Every RTO received only partial acceptance of their compliance filings, with FERC directing further revisions in each case. That means the rules are still being refined — and developers operating in multiple markets face a moving target. Here's the current state:

PJM — furthest along, highest stakes

PJM is the most advanced in implementing Order 2023 reforms. The numbers tell the story:

• Transition Cycle 1 completed November 2025: 130 projects, 17.4 GW studied
• 46,000+ MW now have interconnection agreements (including 18,000 MW from the "Fast Lane" process)
• Transition queue reduced to ~46 GW, expected to clear by end of 2026 in Transition Cycle 2
• First regular Cycle 1 application deadline: April 27, 2026 — a single annual intake window
• Average timeline from request to COD rose from under 2 years (2008) to over 8 years (2025), per RMI analysis

PJM's single annual intake window is the most consequential change for developers. Miss April 27, and you wait until 2027. Submit with incomplete site control documentation, and your application is rejected outright. There is no "submit now, fix later." If you're preparing a PJM Cycle 1 application, our free PJM Cycle 1 Toolkit includes the pre-submission checklist, deposit calculator, and 35-page playbook.

MISO — massive queue, accelerating timelines

• 242 GW waiting to be studied; DPP-2025 launched January 6, 2025 with 78 GW seeking interconnection
• Reformed process targets 373 days from application to GIA — a 26% reduction from historical timelines
• Doubled upfront deposits and introduced automatic withdrawal penalties in 2024
• ~70% of projects in MISO's queue have historically never reached commercial operation
• MISO South clears projects ~9 months faster than MISO North (which handles 70% of volume)

MISO's compressed 373-day target means site control documentation must be ready before the application window — not assembled during the study period. For developers with projects spanning MISO North and South, the timing difference creates an operational challenge: your MISO South project might hit IA execution while your MISO North project is still in study. That means managing different stage-specific thresholds simultaneously across the same portfolio.

CAISO — strictest rules, highest attrition

• Queue dropped from 541 initial submissions (2023) to 255 resubmissions (2025), with only 177 accepted projects after intake scoring — a 67% attrition rate
• Adopted a zonal approach: prioritizes projects in areas with existing/planned transmission capacity, caps at 150% of available capacity per zone
• IPE 5.0 reforms expected to go to CAISO Board March 2026; in place before Cluster 16 opens October 1, 2026
• CAISO is the only RTO that progressively discounts option weights: 1.0 at cluster study, 0.75 at facilities, 0.0 at IA execution

CAISO's 67% attrition rate from initial submission to accepted project is the most aggressive screening in any RTO. Developers who don't have site control locked down before the application window will not survive the intake scoring. CAISO also has unique encumbrance rules — Williamson Act parcels without filed non-renewal notices are excluded from coverage at every meaningful stage.

ISO-NE, NYISO, SPP — catching up fast

• ISO-NE: FERC largely accepted filing in April 2025. 270-day cluster study timeline. Interconnection requests not accepted again until October 5, 2026.
• NYISO: Backlog doubled from 176 projects (2018) to 350 projects (2025). First cluster study kicked off August 2024. Delayed Decision Period 2 for Transition Cluster by 60 days due to National Grid study delays.
• SPP: Queue exceeds 150 GW. Moving from serial to cluster approach. $1.8 billion MISO-SPP JTIQ plan: five 345 kV projects enabling 28.6 GW of mainly renewable generation.

Which RTOs are most at risk for compliance failures

Not all markets carry the same risk. Based on queue size, rule complexity, and enforcement posture, here's our assessment:

If you're developing in PJM or CAISO, the compliance risk is immediate. If you're in MISO, the compressed timeline makes manual tracking increasingly untenable. The common denominator: every market is getting harder, and the cost of a coverage gap is getting steeper.

Why spreadsheets break in 2026

Most mid-market developers — companies with 5 to 50 active projects — still track site control in spreadsheets. Some use land management software that wasn't designed for interconnection compliance. A few have built internal tools. None of these approaches can keep up with what Order 2023 now requires.

Here's what changed:

1. Stage-aware thresholds across 7 markets. A developer with projects in PJM, MISO, and CAISO faces three different deposit schedules, three different option-weight curves, three different encumbrance policies, and three different application windows. Each market has its own stage-specific thresholds. A spreadsheet that shows "92% coverage" doesn't tell you whether that number passes at system impact in PJM (where the threshold is 90%) or fails at cluster study Phase 1 in CAISO (where options might be contributing acreage that gets discounted).
2. Option conversion tracking. Options count at full weight early but drop to zero at IA execution in every RTO. CAISO starts discounting at facilities study. If your coverage calculation doesn't separate option-backed acreage from executed-lease acreage and project forward to each milestone, you won't know you have a problem until you're already past the conversion deadline. See Option-to-Lease Expiration and Interconnection Milestones.
3. Spatial coverage, not parcel counting. Coverage percentage is computed as a spatial union of controlled parcels intersected with the project boundary, divided by the boundary area. Two overlapping parcels don't count twice. A parcel that extends beyond the boundary only counts for the area within the boundary. This requires PostGIS-level spatial computation, not a SUM formula.
4. Escalating financial exposure. With deposits climbing to 20% of network upgrade costs at LGIA execution, the dollar consequence of a coverage error scales with project size. For a portfolio of 10 projects, you might have $20M–$50M in deposits at risk at any given time. That's not a spreadsheet problem. That's an enterprise risk management problem.

The IRA made this worse (in a good way)

The Inflation Reduction Act supercharged the renewable energy pipeline. SEIA projects an additional 160 GW of solar over the next decade compared to a no-IRA baseline, representing $565+ billion in new investment. Solar and battery storage now make up 80% of the interconnection queue.

More projects means more competition for queue positions. More competition means higher scrutiny on site control documentation. The developers who will capture the IRA opportunity are the ones who can demonstrate compliance at every gate. The ones who can't will lose their queue positions to competitors who can.

In the first half of 2025 alone, over $22 billion in renewable projects were canceled, erasing 16,500 jobs and stranding billions in tax-equity capital. Sunk cost per abandoned MW averaged $200,000. These aren't hypothetical losses — they're capital that developers actually spent and will never recover.

Where the compliance market is heading: 2026–2029

Based on the trajectory of FERC enforcement, RTO rule refinement, and market dynamics, here's where we see the compliance landscape moving:

2026: The parallel enforcement year

Every RTO runs reformed cluster studies simultaneously. PJM's Cycle 1 (April), MISO's DPP-2025, CAISO's Cluster 16 (October), ISO-NE reopening (October). Developers with multi-RTO portfolios will face their first experience of managing stage-aware compliance across multiple markets at the same time. Spreadsheet-based tracking will fail visibly for the first time at scale. Early adopters of automated compliance tooling will have a measurable advantage in application acceptance rates.

2027: Co-location and data center demand reshape the queue

FERC's December 2025 order directed PJM to create rules for co-locating large loads (AI data centers) at generating facilities. The DOE ordered FERC to initiate rulemaking for accelerating large-load interconnection by April 30, 2026. Natural gas in the queue surged 72% year-over-year to 136 GW, driven entirely by data center demand. This reshapes the competitive landscape: renewable projects now compete not just with each other, but with gas-backed data center projects that come with stronger balance sheets and faster timelines. Site control documentation quality becomes a differentiator.

2028–2029: Standardization and continuous monitoring

As RTOs complete their first full cycles under the reformed process, expect convergence on site control verification standards. FERC will likely issue further guidance on acceptable forms of site control evidence, potentially requiring machine-readable documentation. The developers who invested in structured compliance data in 2026–2027 will be positioned for this shift. Those still running manual processes will face a compounding disadvantage.

The frugal developer's case for investing now

If you've been in this industry long enough, you've seen plenty of software vendors promise to "revolutionize" your workflow and then fold in 18 months. Healthy skepticism is warranted. But here's the cost-benefit math that's hard to argue with:

What you're already spending

• Land team hours: Manually cross-referencing lease expirations against queue milestones across multiple RTOs. For a 20-project portfolio, this is a full-time job for at least one person — $80K–$120K/year fully loaded.
• Outside counsel review: Having attorneys verify site control documentation before each submission. At $400–$600/hour, a single RTO filing review runs $5K–$15K. Multiply by the number of projects and stages.
• Spreadsheet errors: The coverage number in your spreadsheet says 92%. But it's not doing spatial intersection, it's not discounting options at CAISO facilities study weight, it's not excluding encumbered parcels, and it's not checking BLM ROW status. The RTO's number will be different. If it's below threshold, you find out after you've already submitted — and you've already forfeited your deposit.

What a missed deadline actually costs

• Forfeited deposits: $250K–$10M+ depending on stage and project size.
• Lost queue position: Re-entering the queue means starting the 4+ year process over. In PJM, you wait until the next annual window.
• Stranded development costs: The average sunk cost per abandoned MW is $200,000. For a 150 MW project, that's $30M in development spend that evaporates.
• Reputational cost with investors: Tax-equity partners and project finance lenders are increasingly asking for compliance evidence before funding. A queue withdrawal signals development risk that makes your next project harder to finance.

The question isn't whether you can afford compliance tooling. It's whether you can afford to find out your coverage number is wrong after you've submitted.

What Zonevex does differently

Zonevex is the only platform that runs stage-aware, 5-filter coverage audits against the specific rules each RTO actually enforces. Not a general land management system with a compliance report bolted on. Not a spreadsheet template with conditional formatting. An automated audit engine built for Order 2023 from day one.

• Lease PDF to compliance report. Upload your instruments. Zonevex parses legal descriptions, matches to parcels via cadastral data, computes spatial coverage in PostGIS, and runs the 5-filter audit: active status, eligible instrument type, encumbrance policy, owner signature verification, BLM ROW status gate.
• 7 RTOs, per-stage rules. Coverage is computed against the specific threshold, option weight, and encumbrance policy for your project's current queue stage in PJM, MISO, CAISO, ISO-NE, NYISO, SPP, or ERCOT. Rules sourced from published tariffs and business practice manuals.
• Milestone-aware alerts. Expiration alerts at 365, 180, 90, 60, 30, and 7 days. Option conversion deadlines mapped to queue milestones. You know when a coverage gap is forming before it becomes a compliance failure.
• PostGIS spatial operations. All geometry computed in PostGIS — the same spatial engine used by national mapping agencies. No spreadsheet geometry. No approximations. ST_Union, ST_Area, ST_Intersection on actual parcel polygons against actual project boundaries.

What to do this quarter

Whether you adopt Zonevex or not, here's what every mid-market developer should be doing right now:

1. Audit your option-to-lease expiration dates against queue milestones. How many options expire before your next stage gate? What's your coverage if all options are excluded? That's your IA execution coverage number today. If it's below 100%, start conversion negotiations now.
2. Run your coverage math with the right filters. Your spreadsheet coverage number is not what the RTO will compute. Remove expired instruments. Exclude options if you're approaching IA execution. Exclude encumbered parcels (Williamson Act, conservation easements, Chapter 61A) if your RTO disqualifies them at your current stage. See our RTO threshold reference for the specific rules.
3. Map your deposit exposure. For each project, calculate your current deposit and the next escalation. Know exactly how much capital you have at risk if coverage drops below threshold. If you're filing in PJM, use the free deposit calculator.
4. Evaluate automated compliance tracking. Schedule a demo and bring your hardest project — the one with the most parcels, the most options, the most encumbrances. If Zonevex can handle that one, it can handle your portfolio.

Sources

• FERC Order 2023 — Interconnection Final Rule Explainer
• FERC Order 2023-A — Rehearing and Clarification
• LBNL Queued Up: 2025 Edition — Characteristics of Power Plants Seeking Transmission Interconnection
• LBNL Generator Interconnection Costs Database
• PJM Completes Transition Cycle 1 Studies
• PJM Announces Cycle 1 Application Deadline
• PJM Interconnection Reform Progress Fact Sheet
• RMI: PJM's Speed to Power Problem
• Troutman Pepper: Summary of FERC Order 2023
• Morgan Lewis: Failure to Connect — Grid Challenges Persist
• SEIA: Impact of the Inflation Reduction Act
• Utility Dive: CAISO Board Approves Interconnection Reforms
• Utility Dive: NYISO Reforms Interconnection Queue
• DOE: Tackling High Costs and Long Delays in Clean Energy Interconnection
• MISO Generator Interconnection
• ISO-NE: Understanding the Transitional Interconnection Process

Related articles

• FERC Order 2023 Site Control Coverage Thresholds by RTO and Stage — The definitive per-stage, per-RTO threshold reference table.
• Option-to-Lease Expiration and Interconnection Milestones — How option expirations interact with queue milestones and the conversion timeline.
• Williamson Act Land and CAISO Interconnection Queue — How California agricultural preserves affect CAISO site control coverage.