FERC Order 2023 Site Control Compliance Guide: Everything Developers Need to Know

What FERC Order 2023 is and why it matters

On July 28, 2023, the Federal Energy Regulatory Commission issued Order No. 2023, the most significant reform to generator interconnection procedures in two decades. The order replaced the serial, first-come-first-served queue process that had governed interconnection requests since Order No. 2003 with a new clustered study framework designed to clear the backlog of speculative projects choking every RTO's transmission planning process.

The scale of the problem that Order 2023 addressed was staggering. According to the Lawrence Berkeley National Laboratory's Queued Up 2025 report, over 2,600 GW of generation and storage capacity sat in interconnection queues across the United States at the end of 2024 — more than double the entire installed generating capacity of the country. The median time from interconnection request to commercial operation had ballooned to nearly five years. Only about 14% of projects that entered the queue between 2000 and 2018 ever reached operation.

The root cause was straightforward: it cost almost nothing to enter the queue, and there was no penalty for sitting in it indefinitely. Developers could file speculative applications with minimal land control, no financing, and no realistic path to construction. These speculative projects consumed study capacity, delayed viable projects, and forced RTOs into endless restudies as projects withdrew.

Order 2023 fixed this by requiring developers to demonstrate commercial readiness — including site control — at every milestone in the interconnection process. Projects that cannot prove compliant site control at the required threshold for their current queue stage are subject to automatic withdrawal. The order became effective on November 29, 2023, with most RTOs implementing compliance plans by January 1, 2024. CAISO's compliance filing (ER24-2042) was accepted in May 2025 with an effective date of June 12, 2024.

The order applies directly to the six FERC-jurisdictional RTOs: PJM, MISO, CAISO, ISO-NE, NYISO, and SPP. ERCOT, which operates outside FERC jurisdiction as an intrastate market, is not subject to Order 2023 mandates. However, ERCOT has adopted similar site control requirements as industry best practice, driven in part by project finance lenders and offtake counterparties who increasingly require FERC-equivalent compliance documentation regardless of the market.

The three fundamental changes

Order 2023 restructured the interconnection process around three core principles that together transformed site control from a loose suggestion into a binding compliance gate.

1. Graduated thresholds tied to queue stages

Before Order 2023, most RTOs applied a single site control standard — often vaguely defined — at the point of interconnection request. Some RTOs required "demonstration of site control" without specifying a coverage percentage. Others had no formal requirement at all until late in the process.

Order 2023 mandated that each RTO define stage-specific coverage percentages that increase as a project advances through the interconnection queue. At application, the threshold might be 50%. By system impact study, it rises to 90%. At interconnection agreement (IA) execution, every RTO requires 100% coverage with executed instruments only. This graduated approach accomplishes two things: it gives developers time to assemble land packages while ensuring that only commercially viable projects advance to expensive late-stage studies.

2. Instrument type eligibility rules

The order recognized that requiring 100% executed leases at application would create an impossible chicken-and-egg problem. Developers cannot justify the cost of executing leases across hundreds of parcels before knowing whether their project will survive interconnection studies. Order 2023 solved this by allowing options-to-lease and options-to-purchase at early queue stages while requiring their conversion to executed instruments by IA execution.

Each RTO defines exactly which instrument types qualify at each stage. At early stages, the eligible list is broad: fee simple ownership, executed leases, options-to-lease, options-to-purchase, easements, and right-of-way agreements all count. By IA execution, the list narrows to only executed instruments — options are excluded entirely, and any acreage covered only by unconverted options falls out of the coverage calculation.

3. Financial commitment gates

Order 2023 introduced escalating financial deposits at each queue stage, creating a direct monetary cost for advancing a speculative project. These include study deposits (due at application), readiness deposits (due at key milestones), and withdrawal penalties (assessed if a project exits the queue after consuming study resources). The financial gates work in concert with site control requirements: a developer must demonstrate both adequate coverage and sufficient financial commitment to proceed past each milestone. Use our PJM deposit calculator to model the financial exposure across study stages.

What qualifies as site control

Site control means that the developer has the legal right to use the land within the project boundary for the purpose of constructing and operating a generating facility. The specific instruments that satisfy this requirement vary slightly by RTO, but the core categories are consistent across all markets.

Fee simple ownership

Outright ownership of the parcel. This is the strongest form of site control. The developer holds title to the land and has unrestricted rights to develop it (subject to zoning, permitting, and any encumbrances of record). Fee simple ownership counts at full weight at every stage in every RTO. Title must be evidenced by a recorded deed, and the developer must be the named grantee or a controlled affiliate.

Executed lease

A fully executed land lease granting the developer the right to construct and operate a generating facility on the parcel for a term sufficient to cover the project's expected operating life, typically 25 to 40 years. The lease must be signed by all required parties — including all owners of record for the parcel. If the parcel is held in tenancy-in-common, every co-tenant must sign. An executed lease counts at full weight at every stage, including IA execution. Key provisions that RTOs and lenders look for include: term length, renewal options, permitted use clauses covering energy generation, and subordination, non-disturbance, and attornment (SNDA) agreements if the land is subject to a mortgage.

Option-to-lease

An agreement giving the developer the right — but not the obligation — to execute a lease on the parcel within a defined exercise period. Options are the workhorse instrument for early-stage land assembly because they allow developers to lock up parcels at relatively low cost while interconnection studies proceed. Options count at full weight (1.0) at early stages in most RTOs but are discounted or excluded at later stages. Critically, no RTO accepts options at IA execution. The option must be converted to an executed lease before that milestone or the acreage drops out of the coverage calculation.

Option-to-purchase

Similar to an option-to-lease, but grants the right to purchase the parcel outright rather than lease it. Option-to-purchase instruments follow the same weight and eligibility rules as options-to-lease across all RTOs. They are typically used for parcels where the developer plans to hold fee simple title rather than maintain a long-term lease.

Easement

A recorded easement granting the developer the right to install and operate generating equipment on the parcel. Easements are most commonly used for access roads, transmission lines, substations, and collector systems rather than for the primary generating footprint. However, a properly drafted easement covering generating facility use is accepted as site control at every stage, including IA execution, in all RTOs. The easement must be recorded, and its permitted uses must explicitly include energy generation or the specific infrastructure being placed on the parcel.

Right-of-way (ROW) agreement

A negotiated right-of-way agreement, typically used for linear facilities such as gen-tie lines, access roads, and collector systems. ROW agreements are accepted by all RTOs at all stages. For projects on federal land, the Bureau of Land Management (BLM) ROW permit serves as the site control instrument. CAISO has uniquely granular requirements for BLM ROW permits, requiring progressively higher permit status levels at each queue stage.

BLM ROW permit (CAISO-specific gates)

For projects in CAISO territory that include federal land administered by the Bureau of Land Management, a BLM right-of-way permit serves as the site control instrument. CAISO is the only RTO that gates BLM ROW eligibility by permit status. At pre-application, a filed application (application_submitted) is sufficient. By cluster study, the permit must have reached accepted_for_processing. At facilities study, environmental_review is required. By IA execution, the permit must have reached grant_issued. Given that BLM permitting can take 2 to 5 years, developers who file late risk having their coverage disqualified at critical milestones even though the underlying land is under federal control.

Cross-RTO threshold comparison

The following table consolidates the site control coverage thresholds across all seven RTOs at key queue stages. This is the single reference that shows how requirements differ by market, stage, and instrument type. For the full per-stage breakdown including pre-application and commercial operation stages, see our detailed threshold reference.

* ERCOT thresholds are industry best-practice benchmarks, not FERC-mandated requirements.

Several patterns emerge from this table. First, PJM is the most stringent market, requiring 100% site control from the very first application under its reformed Manual 14H procedures. This is a deliberate filter — PJM's Cycle 1 process is designed to ensure that only shovel-ready projects enter the queue. Second, MISO and SPP share nearly identical threshold structures: 50% at application, 90% at system impact, 100% at IA. Third, CAISO, ISO-NE, and NYISO all apply option weight discounts at their facilities study stage, reducing option-covered acreage to 0.75 weight — a signal to developers that conversion should be underway. Fourth, every FERC-jurisdictional RTO converges to the same endpoint: 100% coverage with executed instruments only at IA execution.

How options work across stages

The treatment of options-to-lease and options-to-purchase is the single most consequential variable in site control compliance. Options are what allow developers to assemble land packages affordably at early stages, but their staged exclusion creates a ticking clock that determines whether a project survives to IA execution.

The option weight lifecycle

Option weight defines how much of an option-covered parcel's acreage counts toward the coverage percentage. The lifecycle follows a predictable pattern:

• Early stages (pre-application, application, feasibility): Options count at 1.0 weight in all RTOs. A 100-acre parcel covered by an option contributes the full 100 acres to the coverage calculation. This gives developers maximum flexibility during the land assembly phase.
• Mid stages (system impact, facilities): Most RTOs maintain 1.0 weight through system impact and facilities study. However, three RTOs — CAISO, ISO-NE, and NYISO — discount options to 0.75 weight at their respective facilities study stages. Under 0.75 weight, a 100-acre parcel covered by an option contributes only 75 acres. This discount is designed to create urgency: developers who are still holding options at facilities study see their effective coverage drop, potentially triggering a threshold breach.
• IA execution: All RTOs set option weight to 0.0. Options are excluded from the eligible instruments list entirely. Any acreage covered only by unconverted options contributes zero acres to coverage. This is absolute and uniform across all seven markets.

The conversion window problem

The gap between option execution and IA execution is where most site control failures originate. A developer who enters the queue with 95% coverage — 50% fee simple, 45% options — appears to be in excellent shape. But that 45% is a liability, not an asset, unless the options are converted to executed leases before IA execution.

Converting an option to an executed lease requires: (1) exercising the option within its exercise period, (2) negotiating and executing the full lease, (3) obtaining all required signatures (including co-tenants in tenancy-in-common), and (4) recording the lease if required by the RTO. This process typically takes 30 to 90 days per parcel, and some landowners are unresponsive or renegotiate terms at exercise. Multiply that by dozens or hundreds of parcels, and the conversion timeline can easily consume 6 to 12 months.

For a detailed analysis of how option expiration dates interact with interconnection milestones, see Option-to-Lease Expiration and Interconnection Milestones.

Encumbrances that can kill site control

Even when a developer holds a valid instrument covering a parcel, the parcel may be disqualified from coverage if it carries an active encumbrance that conflicts with the intended use. Encumbrances are the hidden risk in site control compliance — they do not appear in lease agreements and are often discovered only through title searches or county record reviews.

Mortgages and liens

If the landowner's property is subject to a mortgage, the lender holds a superior interest. In the event of foreclosure, the lender could extinguish the developer's lease. The standard cure is a Subordination, Non-Disturbance, and Attornment (SNDA) agreement executed by the lender. The SNDA subordinates the mortgage to the lease (ensuring the lease survives foreclosure), provides non-disturbance (the lender agrees not to interfere with the developer's use), and requires attornment (the developer acknowledges the lender as landlord if the lender acquires the property). Most RTOs flag parcels with unsatisfied mortgages at system impact and disqualify them at IA execution unless an SNDA is in place.

Conservation easements and restrictions

Conservation easements permanently restrict the use of land for conservation purposes. A parcel subject to a conservation easement that prohibits energy infrastructure development cannot be counted toward site control coverage, regardless of what the lease says. Conservation restrictions vary by state — some allow solar under specific conditions, others prohibit it categorically. At system impact and later stages, most RTOs disqualify parcels with conservation easements from the coverage calculation.

Williamson Act (California)

The Williamson Act (California Land Conservation Act of 1965) provides property tax reductions in exchange for agricultural use restrictions. Land enrolled in a Williamson Act contract cannot be converted to non-agricultural use during the contract term, which is typically 10 years with automatic annual renewal. To develop on Williamson Act land, a developer must file a Notice of Non-Renewal, which starts a 9-year phase-out period, or seek a cancellation through the county — a process that is expensive, politically sensitive, and rarely granted. For CAISO projects, Williamson Act encumbrances are flagged at early stages and can disqualify parcels at system impact and beyond.

Massachusetts Chapter 61 ROFR

In Massachusetts, land enrolled under Chapter 61, 61A, or 61B tax classifications is subject to a municipal right of first refusal (ROFR) when the land is converted from its enrolled use. When a developer exercises an option to lease or purchases agricultural land, the municipality has 120 days to match the purchase terms and acquire the property. During this 120-day window, the parcel's blocks_coverage flag is set to true and the acreage is excluded from coverage calculations in ISO-NE. Developers must account for this window when planning option conversion timelines.

New York Agriculture and Markets Law §305-a

New York's agricultural district law requires that any governmental agency or developer proposing to convert agricultural land within a certified agricultural district file a notice with the Commissioner of Agriculture and Markets. The notice-and-comment process can take 45 to 90 days and must be complete before system impact study submission in NYISO. Failure to complete the notification process does not necessarily prevent development, but it creates a procedural encumbrance that RTOs treat as a disqualifying flag at mid-to-late stages.

Tribal land

Projects on tribal trust land or allotted land held in trust by the Bureau of Indian Affairs face a distinct set of challenges. Leases on trust land require approval from the Bureau of Indian Affairs under 25 CFR Part 162, a process that can take 12 to 24 months. The lease approval process is independent of any RTO's interconnection timeline, and delays are common. Developers must build BIA approval timelines into their site control compliance planning and should not assume that a signed lease is sufficient — the lease is not effective until BIA approval is granted.

Split-estate mineral rights

In states with significant oil and gas activity (Texas, Oklahoma, North Dakota, Pennsylvania, West Virginia), surface and mineral rights are often severed. The mineral rights holder typically has a dominant estate right to access the surface for extraction purposes. If a mineral rights holder exercises their right to drill on a parcel that a developer has leased for solar or wind, the generating equipment may need to be relocated. While split-estate issues do not automatically disqualify a parcel from site control coverage, they create a risk flag that lenders and offtake counterparties will scrutinize.

The compliance workflow

Whether performed manually or through automation, the site control compliance workflow follows seven steps. Each step must be completed before the results are meaningful, and errors in early steps propagate through the entire calculation.

Step 1: Assemble the land package

Collect all instruments (deeds, executed leases, options, easements, ROW agreements) that constitute the project's site control portfolio. Each instrument must be associated with one or more parcels, identified by APN (assessor's parcel number) or legal description. Instrument metadata includes: type, execution date, expiration date (for options), signatory information, and recording status.

Step 2: Parse legal descriptions from instruments

Extract the legal description from each instrument and convert it to a geospatial polygon. Legal descriptions come in three primary formats: metes and bounds (bearing-and-distance calls), PLSS (Public Land Survey System) references, and lot-and-block references. Metes and bounds descriptions must be parsed into coordinate sequences and closed into polygons. PLSS references must be resolved to their geographic extent using the BLM's PLSS dataset. This is the most technically challenging step — errors in legal description parsing produce incorrect parcel geometries that cascade through the coverage calculation.

Step 3: Match parcels to project boundary

Spatially intersect each instrument's parcel geometries with the project boundary polygon. This determines which portions of each parcel fall within the project footprint. Parcels that extend beyond the project boundary are clipped, and only the portion within the boundary counts toward coverage. This step requires spatial database operations (PostGIS ST_Intersection, ST_Area) and must account for coordinate system projections to produce accurate acreage calculations.

Step 4: Calculate coverage percentage

Compute the spatial union of all qualifying parcel geometries within the project boundary. The coverage percentage is: ST_Area(ST_Union(qualifying_parcels)) / ST_Area(project_boundary) * 100. Before a parcel's acreage enters this union, it must pass the five filters: active status, eligible instrument type for the current stage, encumbrance policy compliance, owner signature verification, and BLM ROW status gate (if applicable). Option-covered parcels are weighted according to the RTO's option weight for the current stage.

Step 5: Check against RTO stage-specific threshold

Compare the calculated coverage percentage against the threshold defined for the project's current queue stage in the applicable RTO. If coverage meets or exceeds the threshold, the project passes. If it falls below, the project has a coverage deficiency that must be remediated before the milestone deadline. The threshold is not a property of the RTO alone — it is a function of the RTO, the queue stage, and the instrument types in the portfolio.

Step 6: Identify gaps and at-risk instruments

For projects that fail or are near the threshold, identify the specific parcels and instruments causing the deficiency. Common gap causes include: expired options, parcels with unresolved encumbrances, instruments missing required signatures, and BLM ROW permits that have not reached the required status. Also identify at-risk instruments — options that will expire before the next milestone, parcels with pending ROFR exercises, and instruments with upcoming conversion deadlines.

Step 7: Generate RTO-specific attestation

Produce the compliance documentation required by the specific RTO. Each RTO has its own format, submission requirements, and attestation language. PJM requires a site control attestation as part of the new service request. MISO requires site control evidence with the interconnection application and at each subsequent milestone. CAISO requires detailed site control documentation including BLM ROW status evidence as part of its cluster study process. The attestation must reflect the coverage calculation as of the milestone date, not an earlier snapshot.

Common compliance failures

Site control compliance failures are rarely caused by a lack of land. They are caused by procedural gaps, timing mismatches, and data errors that erode the effective coverage percentage below the required threshold.

Expired options

Options-to-lease typically have exercise periods of 1 to 3 years. If an option expires before the developer exercises it, the parcel drops out of the site control portfolio entirely. This is the most common failure mode. A project that entered the queue with 95% coverage can drop to 75% overnight if a cluster of options expires simultaneously. The cure is proactive option renewal or early exercise, but both require additional capital outlay and landowner cooperation.

Unsigned heirs and tenancy-in-common

When a landowner dies, title passes to heirs. If the estate is not probated promptly, the parcel may be held in tenancy-in-common by multiple heirs, some of whom may be difficult to locate or unwilling to sign. A lease or option signed by only some of the co-tenants is not valid site control for the full parcel. This problem is especially prevalent in the Southeast and Appalachia, where multi-generational family land is common and title records may be incomplete.

Undisclosed encumbrances

A title search performed at lease execution may not reveal encumbrances that are recorded after the search date. Conservation easements, tax liens, judgment liens, and mechanics' liens can all be recorded between the lease date and the compliance milestone date. Developers who rely on stale title searches risk discovering encumbrances at the worst possible time — during a milestone compliance review.

Option expiration before milestone

Interconnection studies routinely experience delays. A project originally expected to reach system impact study within 2 years may not get there for 3 or 4 years. If the developer's options were structured with 2-year terms based on the original timeline, they expire before the milestone arrives. The developer then faces the choice of renewing options (at additional cost, if the landowner agrees), exercising early (committing capital before the project's viability is confirmed), or accepting a coverage reduction.

Incorrect coverage calculation methodology

Coverage calculations must be spatial, not tabular. Simply summing the acreage of controlled parcels and dividing by total project acreage produces incorrect results because: (1) parcels may overlap, (2) parcels may extend beyond the project boundary, and (3) option-weighted parcels contribute fractional acreage that changes by stage. The correct methodology uses a spatial union of clipped, weighted parcel geometries divided by project boundary area — a calculation that requires GIS capabilities.

Wrong threshold applied for the stage

With seven RTOs and up to seven stages each, the matrix of applicable thresholds is large enough that errors occur. A developer who applies MISO's 50% application threshold to a PJM project will be 50 percentage points short. A developer who forgets that CAISO discounts options to 0.75 at facilities study may believe coverage is adequate when it is not. Threshold errors are especially dangerous because they produce false confidence — the developer thinks they are compliant when they are actually deficient.

Timeline realities

The fundamental tension in site control compliance is the mismatch between interconnection study timelines and land instrument terms.

Interconnection studies under the reformed clustered process are designed to take approximately 3 to 5 years from application to IA execution. In practice, the timeline can extend further due to restudies, model corrections, and cluster resizing. A project entering PJM's Cycle 1 in 2026 may not reach IA execution until 2029 or 2030.

Options-to-lease, by contrast, typically have exercise periods of 1 to 3 years. The economic logic of options depends on their short duration — landowners accept lower option payments in exchange for a limited commitment period. Extending option terms to 5 years or longer is possible but significantly increases per-acre option costs and may require higher annual option payments to keep landowners engaged.

This mismatch creates a critical conversion window. A developer who enters the queue with a portfolio that is 50% fee simple and 45% options (95% total coverage) must convert those options to executed leases before IA execution. If the options expire in year 2 and IA execution does not occur until year 4, the developer has a 2-year gap during which they must either: (a) exercise the options early and bear the lease costs during the study period, (b) renew the options for additional terms, or (c) accept the risk that some parcels will be lost.

The cost of early exercise is substantial. Executing a lease triggers annual rent payments that can range from $800 to $2,000 per acre per year for solar-suitable land in competitive markets. For a 200 MW solar project covering 1,500 acres, converting 45% of the portfolio (675 acres) from options to leases 2 years early represents $1.1 million to $2.7 million in additional rent payments before the project generates a single kilowatt-hour.

For a detailed walkthrough of conversion timing strategies and risk mitigation approaches, see Option-to-Lease Expiration and Interconnection Milestones.

2026 is the inflection year

Every reformed interconnection queue is now running simultaneously, and the transition period from the old serial process to the new clustered study framework is effectively over.

PJM Cycle 1 — the first cluster study window under PJM's reformed procedures — opens on April 27, 2026. PJM's application window requires 100% site control at submission, the most stringent application-stage requirement of any RTO. The 2,600+ projects that sat in PJM's legacy queue have been transitioned or withdrawn, and the new cycle starts with a clean slate. Developers who are not ready on April 27 will wait for Cycle 2.

CAISO Cluster 16 opens October 1, 2026, with the reformed procedures fully in effect. CAISO's cluster study process requires 90% coverage at Phase 1, with BLM ROW permits at accepted_for_processing status. Projects on BLM land that have not yet filed their ROW applications are already behind.

MISO, ISO-NE, NYISO, and SPP are all running their reformed study processes concurrently. For MISO, the transition cluster studies have been processing since 2024, and new definitive planning phase (DPP) cycles continue to accept applications under the Order 2023 framework. ISO-NE and NYISO have implemented their compliance plans and are processing cluster studies with the new site control requirements in effect.

The practical consequence is that every developer in every market is now subject to graduated, stage-specific site control requirements with automatic withdrawal consequences for non-compliance. The era of entering the queue with a speculative land position and figuring it out later is over. For the full market-by-market analysis of why 2026 is the critical year, see FERC Order 2023 Compliance in 2026: Why This Is the Year.

How to stay compliant

Maintaining site control compliance across a multi-year interconnection process requires continuous monitoring, not one-time verification. The land package that passes at application may fail at system impact study if options expire, encumbrances are recorded, or coverage is recalculated with tighter instrument eligibility rules.

Proactive monitoring

Track every instrument's status, expiration date, and conversion deadline against the project's interconnection milestone schedule. Set alerts for option expirations, ROFR exercise windows, BLM ROW status changes, and encumbrance recordings. A single expired option on a 50-acre parcel can drop coverage below the threshold on a project that was otherwise compliant.

Milestone-aware alerts

Compliance is not static — the threshold changes at each stage, and so does the eligibility of instrument types and the treatment of options. Alerts must be tied to the project's specific milestone schedule, not generic calendar dates. When a project advances from feasibility to system impact study, the threshold may jump from 50% to 90% and the encumbrance policy may shift from "flag" to "disqualify." Both changes can cause a project that was compliant at the previous stage to fail at the new one.

Automated coverage calculation

Manual coverage calculations using spreadsheets are error-prone and cannot account for spatial overlaps, boundary clipping, or option weight adjustments. Accurate coverage requires a spatial database (PostGIS) that computes the union of qualifying parcel geometries against the project boundary, applies option weights, and filters for instrument eligibility and encumbrance policy. This calculation must be repeatable at any time, not just at milestone deadlines.

RTO-specific export generation

Each RTO requires compliance documentation in its own format with its own attestation language. The ability to generate RTO-specific reports — showing the coverage calculation, eligible instruments, encumbrance status, and threshold compliance at the current stage — is essential for milestone submissions. For a reference of the threshold rules by RTO and stage, see our coverage thresholds reference.

Zonevex automates this entire workflow: from lease PDF ingestion and legal description parsing through spatial coverage calculation and RTO-specific compliance reporting. The platform tracks instrument status changes, fires milestone-aware alerts when coverage is at risk, and generates the attestation documentation required for each RTO's submission process. It is built specifically for the post-Order 2023 compliance landscape where site control is a continuous obligation, not a one-time checkbox.

Sources

• FERC Order 2023 — Interconnection Final Rule Explainer
• LBNL Queued Up 2025 — Characteristics of Power Plants Seeking Transmission Interconnection
• PJM Interconnection Queue and Manual M-3.1S / Manual 14H
• MISO Generator Interconnection Procedures
• CAISO GIDAP Business Practice Manual
• CAISO Compliance Filing ER24-2042 (FERC eLibrary)
• ISO-NE Generator Interconnection Standards
• NYISO Generator Interconnection Procedures
• SPP Generator Interconnection (Tariff Attachment V)

Related articles

• FERC Order 2023 Site Control Coverage Thresholds by RTO and Stage — The per-stage, per-RTO threshold reference table with eligible instruments, option weights, encumbrance policies, and BLM ROW status gates.
• Option-to-Lease Expiration and Interconnection Milestones — How option expirations interact with queue milestones and the conversion timeline that determines whether your coverage holds.
• FERC Order 2023 Compliance in 2026: Why This Is the Year — The full market analysis: RTO implementation status, deposit escalation math, queue data, and where the compliance landscape is heading.
• Williamson Act Land and CAISO Interconnection Queue — How California agricultural preserves affect CAISO site control coverage and the non-renewal notice workflow.

For answers to common questions about eligible instruments, option weights, the 5-filter audit, and SNDA requirements, see our FERC Order 2023 site control FAQ. For definitions of key terms used throughout this guide, visit the Zonevex Glossary.