PJM Site Control Requirements in 2026: The Complete Developer Guide

If you are developing a utility-scale generation project in PJM's footprint, 2026 is the year everything changed. PJM's transition from a serial interconnection queue to a cycle-based process under FERC Order 2023 did not just shuffle procedural timelines — it fundamentally redefined what it means to demonstrate site control, when you must demonstrate it, and what happens if you fall short. The Cycle 1 application window closes on April 27, 2026, and the requirements are unforgiving.

This guide is written for developers, land managers, and interconnection attorneys who need to understand every dimension of PJM site control compliance in 2026. It covers the regulatory changes, stage-by-stage thresholds, eligible instruments, the tenancy-in-common problem, anti-straw entity rules, setback buffer control, multi-state permitting complexity, financial deposit exposure, option conversion planning, encumbrance handling, the M-3.1S attestation format, and the consequences of failure. If you read one article before filing your Cycle 1 application, make it this one.

What changed for PJM in 2026

Before FERC Order 2023, PJM operated a serial interconnection queue. Projects entered the queue individually, were studied in the order they arrived, and site control requirements were checked at a single milestone. The system was designed for a world with dozens of interconnection requests per year. By 2023, PJM had over 2,600 projects backlogged in its queue, with an average wait time exceeding five years from application to interconnection agreement. The queue was clogged with speculative projects that had secured little or no land, filed applications to hold queue positions, and had no realistic path to commercial operation.

FERC Order 2023, issued in July 2023 and effective January 1, 2024 for PJM, replaced this model with a cluster-based cycle process. PJM's implementation is codified in Manual 14H (effective 2025-2026) and accompanying tariff revisions. The core change is this: PJM now requires 100% site control at the time of application for new service requests. Not 50%. Not "reasonable demonstration." One hundred percent.

This is a massive departure from the pre-Order 2023 regime, where developers could enter the queue with minimal land control and assemble their site control packages over the multi-year study process. Under the new rules, if you cannot demonstrate control over 100% of your project footprint on the day your application is submitted, your application is deficient. There is no cure period at application. There is no provisional acceptance pending further documentation. You either have it or you do not.

The shift extends beyond thresholds. PJM's new cycle process introduces readiness deposits ($4,000 per MW, up to $2 million), tiered study deposits ($75,000 to $400,000), Decision Point withdrawal gates, and escalating financial penalties for projects that enter the queue and subsequently withdraw. The entire structure is designed to filter out speculative projects at the front door, not five years into the study process.

For the full cross-RTO comparison of how FERC Order 2023 changed site control across all seven markets, see FERC Order 2023 Site Control Coverage Thresholds by RTO and Stage.

PJM site control thresholds by stage

PJM's site control requirements are not a single number — they vary by queue stage, and the rules governing which instrument types qualify change at each stage. The following table reflects PJM's current requirements under Manual 14H and the FERC Order 2023 compliance filing.

Several things stand out. First, PJM's thresholds are the most aggressive of any FERC-jurisdictional RTO. MISO, ISO-NE, NYISO, and SPP all start at 50% at application and ramp to 90% at System Impact Study before reaching 100% at IA execution. PJM starts at 100% and stays there. There is no ramp.

Second, options-to-lease are accepted at full weight (1.0) through the Facilities Study phase. This means an option-to-lease covering a parcel is treated identically to an executed lease for coverage calculation purposes at application through facilities. However, at IA execution and beyond, options are excluded entirely. The option weight drops to 0.0, and any acreage covered only by an unconverted option falls out of the coverage calculation completely.

Third, encumbrances are disqualified from application onward. Unlike some RTOs that merely flag encumbrances at early stages, PJM takes the strict approach: if a parcel has an unresolved encumbrance (mortgage, lien, conservation easement), the instrument covering that parcel is excluded from the coverage calculation starting at application. This policy does not change at later stages — it is disqualify all the way through.

What qualifies as site control for PJM

PJM recognizes the following instrument types as demonstrating site control:

• Fee simple ownership. Outright ownership of the parcel. The gold standard — no expiration, no counterparty risk, no conversion required.
• Executed lease. A fully executed lease agreement between the developer (or an affiliated entity) and the landowner. Must be signed by all parties, covering the project footprint, and must not have expired.
• Option-to-lease. A contractual right to execute a lease at a future date. Accepted at full weight (1.0) through Facilities Study but excluded at IA execution. Must be active (not expired) and signed by all required owners.
• Option-to-purchase. A contractual right to purchase the property. Same treatment as option-to-lease: full weight through Facilities Study, excluded at IA execution.
• Easement. A recorded easement granting the developer rights to use the property for the generation facility. Accepted at all stages including IA execution.
• Right-of-way (ROW) agreement. An agreement granting access and use rights for transmission interconnection or generation facility components. Accepted at all stages.

Each instrument submitted must satisfy three conditions to count toward coverage: (1) the instrument must be active — not expired, terminated, or superseded; (2) the instrument must cover the project footprint — the legal description in the instrument must map to parcels within the project boundary; and (3) the instrument must be signed by all required owners. A lease signed by one of three tenants-in-common on a parcel does not count. All natural-person owners must have executed the instrument.

The M-3.1S attestation format — PJM's required submission template — requires developers to present each instrument in a structured parcel table. We cover the specific format requirements in the M-3.1S attestation section below.

The tenancy-in-common problem

If there is one issue that causes more PJM site control rejections than any other, it is the tenancy-in-common problem. And it is not a legal technicality — it is a practical crisis that can derail a project months after land agents believe they have secured control.

A tenancy-in-common (TIC) exists when two or more parties hold undivided fractional interests in the same property. Each tenant owns a percentage of the whole — one-third, one-sixth, one-twelfth — but no tenant owns any specific physical portion of the parcel. This is the default form of co-ownership in most PJM states when property passes to multiple heirs without a will specifying otherwise.

The problem for developers is straightforward: PJM requires that all natural-person owners sign the instrument. A lease signed by two of three tenants-in-common is not a valid lease for site control purposes. It does not count for two-thirds of the parcel. It does not count at all. A single unsigned heir voids the entire instrument for that parcel.

In the rural mid-Atlantic and Appalachian regions that dominate PJM's footprint for utility-scale solar and wind development, TIC ownership is extraordinarily common. Properties that have been in families for generations often have fractional interests spread across dozens of heirs. The original owners may have died intestate (without a will), and their interests were inherited by their children, who then died intestate, and so on through multiple generations. A 200-acre parcel in rural Virginia or West Virginia may have 15 to 30 owners of record, some of whom are deceased with estates still in probate, some of whom have moved out of state with no current address on file, and some of whom may not even know they hold an interest in the property.

The practical difficulty is enormous. Heir searches can take months. Title companies must trace each fractional interest through decades of deed records, probate filings, and intestacy statutes. Unknown heirs require court proceedings to establish guardianship or to authorize sale. Estates in probate require executor signatures, which may require court approval for the specific transaction. And every single one of these issues must be resolved before the instrument is valid for PJM site control purposes.

Developers who discover TIC issues after filing their Cycle 1 application have no cure period. The application is deficient on submission. The parcel's acreage is excluded from the coverage calculation, and if the remaining coverage falls below 100%, the application fails.

Best practice: Run title searches on every parcel in your project footprint at least six months before the application deadline. Flag any parcel with more than two owners of record for immediate legal review. Budget $2,000 to $5,000 per parcel for heir search and curative work on TIC properties.

The anti-straw entity rule

PJM's site control requirements do not stop at the surface-level owner on the lease. When the landowner is an LLC, limited partnership, or other legal entity, PJM requires that the ownership chain be resolved to natural persons. The purpose is to prevent developers from creating shell entities that nominally "own" the land without any natural person actually authorizing the grant of site control.

In practice, this means that if your lease counterparty is "Smith Family Land Holdings, LLC," PJM may require documentation showing who the members of the LLC are, who has signing authority, and whether the LLC's operating agreement authorizes the signatory to execute a lease for the term required. If the LLC is itself owned by another LLC (a multi-tier structure), PJM expects the chain to resolve through to identifiable natural persons at some level.

Foreign nationals or entities organized outside the United States present additional complexity. PJM does not have a blanket prohibition on foreign ownership, but foreign entities without transparent ownership structures raise flags during review. CFIUS (Committee on Foreign Investment in the United States) considerations may apply for projects near military installations or critical infrastructure, which are common in PJM's mid-Atlantic footprint.

The practical implication for land teams: when negotiating leases with entity counterparties, obtain and retain copies of the operating agreement, articles of organization, and any resolutions authorizing the signatory to execute the lease. Include these in the M-3.1S attestation package.

Setback buffer control

One of the most frequently misunderstood PJM site control requirements involves setback buffers. PJM requires that setback areas around generating facilities be under site control even if no equipment is placed in those areas. The logic is straightforward: if state or local regulations require a 150-foot setback from the property boundary, and your generation equipment is placed within 150 feet of a boundary with a parcel you do not control, you have a compliance problem regardless of whether you plan to place equipment in the setback zone.

The challenge is that setback distances are set by state and local jurisdictions, not by PJM. And PJM's footprint spans 13 states plus the District of Columbia, each with its own setback regime. The variation is substantial:

• Pennsylvania: No statewide solar setback standard. County-level ordinances vary from 50 feet to 300 feet from property lines. Many rural counties have no solar-specific ordinance at all, defaulting to general zoning setbacks.
• Virginia: The Virginia Department of Energy recommends setbacks of 100 feet from occupied structures and 50 feet from property lines, but local ordinances may be more restrictive. Loudoun County, a major solar development area, requires 100 feet from adjacent residential property lines.
• Ohio: The Ohio Power Siting Board (OPSB) requires a minimum setback of the greater of 75 feet from the nearest property line or the turbine height plus 10% for wind projects. Solar setbacks are project-specific but typically 25 to 100 feet.
• Maryland: County-level regulation. Frederick County requires 100 feet from residential property boundaries. Howard County requires 300 feet from residential structures.
• New Jersey: The NJ BPU does not set statewide setbacks for ground-mounted solar. Municipal ordinances vary widely, with setbacks from 25 feet to 200 feet depending on zoning district.
• Illinois: County-level permitting with setbacks typically ranging from 50 feet to 150 feet from property lines, varying by county ordinance.
• Indiana: County-level regulation. Some counties have adopted setbacks of 300 feet or more from adjacent residential property lines for utility-scale solar.
• West Virginia: Limited solar-specific regulation. General zoning setbacks apply, which are often minimal in rural areas.

The practical consequence is that your site control boundary must extend beyond the physical equipment footprint by the applicable setback distance in every direction. If your project boundary accounts for a 50-foot setback but the local ordinance requires 150 feet, you may need site control over additional parcels that your original land package did not include. Discovering this after the application deadline is a fatal error.

13 states, 13 regulatory regimes

PJM's footprint is the largest of any RTO in the United States, covering all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia, plus the District of Columbia. Each jurisdiction has its own public utility commission (or equivalent), its own permitting process for generation facilities, and its own timeline for approvals.

The relevant regulatory bodies and approximate permitting timelines include:

• Pennsylvania PUC (PA PUC): Siting approvals for generation facilities. Timeline: 180-270 days depending on project size and hearing requirements.
• New Jersey Board of Public Utilities (NJ BPU): Certificate of need and environmental review. Timeline: 120-240 days. Agricultural land restrictions under the Right to Farm Act may apply.
• Maryland Public Service Commission (MD PSC): Certificate of Public Convenience and Necessity (CPCN) for facilities over 2 MW. Timeline: up to 388 days, one of the longest in PJM's footprint. Includes evidentiary hearing process.
• Virginia State Corporation Commission (VA SCC): Permit by rule for solar facilities over 5 MW. Timeline: 180-300 days. DEQ environmental review runs in parallel.
• Ohio Power Siting Board (OPSB): Certificate of environmental compatibility and public need for major utility facilities. Timeline: 240-365 days. Mandatory public hearing process.
• Illinois Commerce Commission (IL ICC): County-level permitting for most solar projects. Timeline: as short as 75 days for county-level approvals in favorable jurisdictions. State-level review under the Illinois Power Agency Act for specific programs.
• Indiana Utility Regulatory Commission (IURC): Certificate of public convenience and necessity. Timeline: 150-270 days.

The critical insight for PJM developers is this: a site control package that passes PJM's interconnection review can still stall on state permits. PJM evaluates site control against its own thresholds and instrument eligibility rules. State regulatory bodies evaluate the project against environmental, land use, agricultural preservation, and public interest standards. These are parallel tracks, and they do not necessarily align on timeline.

A developer who files a PJM Cycle 1 application on April 27, 2026, with 100% site control may simultaneously be 12 months away from obtaining a Maryland CPCN or an Ohio OPSB certificate. The site control is valid for PJM purposes, but the project cannot begin construction until state permits are in hand. Misalignment between interconnection milestones and state permitting timelines is one of the primary drivers of Decision Point withdrawals and associated financial penalties.

Financial deposits and withdrawal penalties

PJM's new cycle-based process introduces a financial commitment structure designed to filter out speculative projects. Understanding the full deposit and penalty exposure is essential for any developer considering a Cycle 1 application.

Study deposits

Study deposits are due at application and are tiered by project size:

These deposits fund PJM's cluster study costs (feasibility, system impact, and facilities studies). They are partially refundable if the project completes the study process, but they are fully forfeited if the project withdraws after Decision Point 1.

Readiness Deposit No. 1

In addition to the study deposit, PJM requires a Readiness Deposit of $4,000 per MW, up to a maximum of $2,000,000. For a 200 MW solar project, that is $800,000. For a 500 MW project, it is the $2M cap. This deposit is due at application alongside the study deposit and serves as a financial commitment signal.

Decision Point withdrawal mechanics

PJM's cycle process includes Decision Points — formal gates where developers must elect to proceed or withdraw. The financial consequences escalate at each gate:

• Pre-Decision Point 1 withdrawal: Study deposit is refundable minus PJM's actual study costs incurred to date. Readiness deposit is refundable.
• Post-Decision Point 1 withdrawal: 100% of the study deposit is forfeited. The developer is also allocated a share of the cluster's network upgrade costs based on their project's proportional impact on the transmission system.
• Post-Decision Point 2 withdrawal: All deposits forfeited plus full allocation of assigned network upgrade costs.

The network upgrade cost allocation is where the financial exposure becomes significant. For a 200 MW project in a cluster where $50 million in network upgrades have been identified, the developer's share could range from $2 million to $15 million depending on the project's proportional contribution to the upgrade requirements. Combined with $500,000+ in forfeited study and readiness deposits, a post-DP1 withdrawal on a mid-sized project can easily exceed $3 million in total losses.

Use our PJM Cycle 1 Deposit Calculator to model your specific exposure across three network upgrade cost scenarios.

Option-to-lease conversion timeline

The interaction between option-to-lease instruments and PJM's queue timeline is one of the most dangerous traps in the new cycle process. Understanding the math is critical.

Options-to-lease count at full weight (1.0) through the Facilities Study phase. They are excluded at IA execution. Under PJM's current Cycle 1 timeline projections, the approximate milestones are:

• Application close: April 27, 2026
• Cluster study begins: ~Q3 2026
• Decision Point 1: ~Q1 2027
• Decision Point 2: ~Q3 2027
• IA execution: ~2028-2029

Now consider the typical option-to-lease term. Most options signed for utility-scale solar projects in PJM's footprint have initial terms of 3 to 5 years with optional extension periods. An option signed in early 2024 with a 3-year initial term expires in early 2027. An option signed in mid-2025 with a 3-year term expires in mid-2028.

If IA execution occurs in 2028 or 2029, options signed in 2024-2025 may expire before the developer reaches the stage where conversion is mandatory. Even if the option has not expired, conversion requires negotiation of lease terms, execution by all parties (including all TIC owners), and potentially subordination agreements with lenders. This process takes 6 to 12 months for straightforward conversions and 12 to 24 months for parcels with TIC ownership or encumbrance issues.

The planning implication: developers must begin option conversion at least 12 months before their projected IA execution date. For Cycle 1 projects, that means conversion planning should begin no later than Q1 2027, even though options remain valid at full weight through the study process. Waiting until PJM signals that IA execution is approaching is too late. For a detailed walkthrough of how option expirations interact with queue milestones across all RTOs, see Option-to-Lease Expiration and Interconnection Milestones.

Encumbrance handling

An encumbrance is any third-party interest in the property that may restrict the developer's ability to use it for generation purposes. Common encumbrances in PJM's footprint include:

• Mortgages. The most common encumbrance. If the landowner has a mortgage on the leased property, the lender has a superior lien. In a foreclosure, the lender could terminate the lease. PJM treats mortgaged parcels as encumbered.
• Liens. Tax liens, mechanics' liens, and judgment liens against the property. Same treatment as mortgages for site control purposes.
• Conservation easements. Permanent restrictions on land use, typically held by a land trust or government agency. Conservation easements that prohibit commercial energy development are disqualifying. Easements that permit energy development with conditions may be acceptable if the conditions are satisfied.
• Agricultural preservation easements. Common in Pennsylvania, Maryland, and New Jersey. These may prohibit non-agricultural use of the land, including solar development. The interaction with state agricultural preservation programs varies by jurisdiction.

PJM's encumbrance policy under the FERC Order 2023 compliance filing is disqualify from application onward. This is a strict policy: if a parcel has an unresolved encumbrance, the instrument's acreage is excluded from the coverage calculation. There is no "flag and monitor" grace period at early stages.

The SNDA cure

The standard cure for mortgage encumbrances is a Subordination, Non-Disturbance, and Attornment (SNDA) agreement. An SNDA is a tri-party agreement among the developer, the landowner, and the lender in which the lender agrees to subordinate its lien to the lease and to not disturb the developer's rights in the event of foreclosure. In exchange, the developer agrees to attorn (recognize) the lender as the new landlord if the lender takes title.

SNDAs are standard commercial real estate instruments, but they take time to negotiate. Lenders may charge $2,000 to $10,000 in legal fees to review and execute an SNDA, and the process typically takes 30 to 90 days from request to execution. For a project with 30 leased parcels, each with a different lender, the cumulative time and cost to secure all required SNDAs can be substantial.

Developers should identify all encumbrances in their title searches and begin SNDA negotiations at least 90 days before the application deadline. An instrument that would otherwise count toward coverage but is disqualified due to an unresolved mortgage can be the difference between 100% and 97% — and at PJM, 97% is a failure.

The PJM M-3.1S attestation

PJM requires site control documentation to be submitted in a specific format governed by the M-3.1S attestation template. This is not a freeform narrative — it is a structured parcel table with mandatory fields. Formatting errors are one of the most common causes of deficiency notices, and deficiency notices at application can delay or disqualify the entire submission.

The M-3.1S parcel table requires the following fields for each instrument:

• Parcel identification number (APN/PIN). The county assessor's parcel number for each parcel covered by the instrument. Must match the county's format exactly.
• County and state. The jurisdiction where the parcel is located.
• Instrument type. Fee simple, executed lease, option-to-lease, option-to-purchase, easement, or ROW agreement.
• Execution date. The date the instrument was fully executed (all parties signed).
• Expiration date. For options and leases with defined terms, the date the instrument expires. Must demonstrate that the instrument will remain active through the projected study timeline.
• Owner name(s). All natural-person or entity owners on the instrument. For TIC properties, every owner must be listed.
• Signatory name(s). The names of all parties who actually signed the instrument. Must match the owner list — any owner who did not sign renders the instrument invalid.
• Parcel acreage. The total acreage of the parcel as recorded by the county assessor.
• Encumbrance status. Whether the parcel has known encumbrances (mortgages, liens, conservation easements) and the status of any curative instruments (SNDAs).

Common formatting errors that cause rejection

• APN mismatch. Using an outdated parcel number after a county replatting, or formatting the APN differently from the county's official format (dashes vs. periods, leading zeros).
• Missing signatories. Listing all owners but only including signatures from the primary contact. PJM verifies that every listed owner has a corresponding signature.
• Expired instruments. Submitting an option that expired between the time the package was assembled and the application deadline. Always verify expiration dates within 48 hours of submission.
• Inconsistent acreage. Using GIS-calculated acreage instead of the county assessor's recorded acreage. PJM uses the assessor's figure for verification.
• Missing encumbrance disclosure. Failing to disclose known mortgages. PJM may cross-reference title records, and an undisclosed encumbrance that surfaces during review will trigger a deficiency notice.

What happens if you fail

The consequences of falling below PJM's site control threshold depend on when the deficiency is identified.

At application

If your application is submitted with coverage below 100%, PJM issues a deficiency notice. Under the new cycle-based process, there is no cure period at application for site control deficiencies. The application window closes on April 27, 2026, and the coverage must be demonstrated as of that date. A deficient application is rejected, and the developer must wait for the next cycle to reapply.

The financial consequence at application is relatively limited: the study deposit and readiness deposit are returned (minus any processing fees). The real cost is the time lost — waiting for Cycle 2 means a delay of 12 to 18 months before the project can re-enter the queue.

At Decision Points

If coverage falls below threshold at a Decision Point (for example, because an option expired or an encumbrance was discovered), the developer faces a binary choice: cure the deficiency before the Decision Point deadline, or withdraw. Unlike application, Decision Points do allow a limited cure period, but the window is narrow (typically 30 days). If the deficiency cannot be cured, withdrawal is mandatory.

Post-Decision Point 1 withdrawal triggers full study deposit forfeiture plus network upgrade cost allocation. For a 200 MW project with $50 million in cluster upgrades, the total financial exposure can exceed $3 million. There are no extensions and no appeals process.

At IA execution

IA execution requires 100% coverage with executed instruments only — no options. If the developer has not converted all options to executed leases by IA execution, the unconverted parcels drop out of the coverage calculation. If coverage falls below 100%, the interconnection agreement is not executed, the project is terminated, and all deposits are forfeited. At this stage, the developer has already invested 2-3 years in the study process and hundreds of thousands of dollars in deposits and upgrade cost allocations. Failure at IA execution is the worst-case financial outcome.

Putting it all together: a Cycle 1 compliance checklist

For developers preparing a PJM Cycle 1 application before the April 27, 2026 deadline, the following sequence represents the minimum diligence path:

1. Run title searches on every parcel in the project footprint. Identify all owners of record, TIC interests, and encumbrances. Begin this process at least 6 months before the deadline.
2. Resolve all TIC ownership issues. Conduct heir searches. Secure signatures from every natural-person owner. Budget 3-6 months for curative work on complex TIC properties.
3. Negotiate SNDAs for every encumbered parcel. Begin SNDA requests at least 90 days before the deadline. Track each SNDA through execution.
4. Verify setback compliance. Confirm state and local setback requirements for every parcel in every jurisdiction your project touches. Secure site control over setback buffer areas.
5. Resolve entity ownership chains. For every LLC or entity counterparty, obtain operating agreements and signing authority documentation.
6. Prepare the M-3.1S attestation. Use the correct APN format per county. Verify every expiration date. Cross-check signatory lists against owner lists. Disclose all known encumbrances.
7. Calculate total financial exposure. Model study deposits, readiness deposits, and potential withdrawal penalties across three network upgrade cost scenarios using the PJM Deposit Calculator.
8. Plan option conversion timeline. Identify every option-to-lease in your portfolio. Calculate expiration dates against projected IA execution timing. Begin conversion negotiations at least 12 months before projected IA execution.

The free PJM Cycle 1 Submission Toolkit includes a 35-page playbook, a 49-item pre-submission checklist, a financial calculator, a POI workbook, a readiness scorecard, and a deficiency cure playbook covering all of these steps.

Sources

• FERC Order 2023 — Interconnection Final Rule Explainer
• PJM Manual 14H — Generation and Transmission Interconnection Process (Cycle-Based)
• PJM Manual 14G — Generation Interconnection Requests
• PJM Interconnection Applications & Forms (including M-3.1S)
• LBNL Queued Up 2025 — Characteristics of Power Plants Seeking Transmission Interconnection

Related articles

• FERC Order 2023 Site Control Coverage Thresholds by RTO and Stage — The cross-RTO reference table for all seven markets.
• Option-to-Lease Expiration and Interconnection Milestones — How option expirations interact with queue milestones and the conversion timeline.
• FERC Order 2023 Compliance in 2026: Why This Is the Year — Full market analysis of the 2026 compliance landscape across all RTOs.