What is the difference between contingent facilities and affected systems?

Contingent facilities are network upgrades whose completion is required before the project can interconnect at its full MFO. They are typically allocated wholly or partly to the requesting project. Affected systems are upgrades on neighboring transmission systems (other RTOs or non-PJM utilities) whose facilities are impacted by the new generation. Affected systems coordination is governed by inter-RTO agreements and adds schedule risk that is not under PJM's direct control.

What does the Phase I Cost Summary actually contain?

The Cost Summary is a tabular breakdown of every network upgrade allocated to the project, with a separate line for each facility, the cost estimate, the allocated share, and the responsible party. It includes direct attachment facilities, contingent facilities, and affected system upgrades. The total at the bottom is the project's allocated network upgrade cost — the number that drives the Decision Point I withdrawal economics.

How does the TC1 baseline help interpret Cycle 1 Phase I results?

Transition Cycle 1 (TC1) was the first cycle PJM ran under the new cycle process. Approximately 35% of TC1 capacity advanced past Phase I; battery storage was the strongest performer at 18% of advancing capacity; and the average allocated network upgrade cost was approximately $206/kW. These benchmarks let a Cycle 1 developer evaluate whether their Phase I cost is favorable, neutral, or adverse relative to the TC1 distribution. The published AF2-126 Phase I report is a public reference for what an advancing Phase I result looks like.

When do I have to commit to Phase II after seeing Phase I results?

Decision Point I (DP1) is the formal go/no-go milestone after Phase I results. The DP1 election window is set by Manual 14H Section 8 and is typically 30 to 60 calendar days from issuance of the Phase I report. The developer either elects to continue into Phase II (committing additional study deposits and the readiness deposit), withdraws, or modifies the request within the bounds of Manual 14H Section 7.2.

How to Read PJM Cycle 1 Phase I System Impact Study Results: A 15-Section Walkthrough

Q: What is a PJM Phase I System Impact Study?

Phase I is the first of two engineering studies in the PJM cycle process. It quantifies the network upgrades and contingent facilities required to interconnect a project at its requested Maximum Facility Output (MFO), and produces a Cost Summary that allocates costs between the requesting project and other queued projects. Phase I results trigger Decision Point I, at which the developer must commit to continue into Phase II, withdraw, or modify the request.

What Phase I is and what it produces

The Phase I System Impact Study (SIS) is the first of two engineering studies in the PJM cycle process. It quantifies the network upgrades and contingent facilities required to interconnect a project at its requested Maximum Facility Output (MFO), and produces a Cost Summary that allocates costs between the requesting project and other queued projects. Phase I is governed by PJM Manual 14H Section 8 and Manual 14C, with the Tariff anchor in Part VII, Subpart B.

Phase I results are the trigger for Decision Point I, the first formal go/no-go milestone in the cycle. The developer must commit to continue into Phase II, withdraw, or modify the request within the Manual 14H Section 7.2 grammar. The Phase II study commitment includes additional study deposits and the readiness deposit; withdrawal returns deposits less actual study cost.

The published AF2-126 Phase I report from Transition Cycle 1 (TC1) is a useful public reference for what an advancing Phase I report looks like. It contains the same 15-section structure that Cycle 1 reports follow, with the only differences being the cycle naming convention and a small number of new sections introduced by the FERC Order 2023 cycle template.

The 15-section Phase I report, at a glance

Every Phase I System Impact Study report contains 15 standardized sections, in roughly the order below. The section numbering is consistent across reports, which makes it possible to navigate directly to the line items that drive the Decision Point I decision.

§	Section	What it tells you	Where DP1 risk hides
1	Executive Summary	The headline number: total allocated network upgrade cost.	None — this is the headline.
2	Project Description	MFO, technology, POI, in-service date.	Confirm POI matches your design. Wrong POI invalidates the study.
3	Study Methodology	Which load and dispatch case PJM used.	Off-baseline studies signal modeling assumptions you may want to challenge.
4	Study Cases	The peak, light load, and seasonal cases.	If your project shows constraints only in light load, watch for affected systems exposure.
5	Steady State Analysis	Thermal and voltage violations identified.	Violations not allocated to your project may still appear as contingent facilities.
6	Stability Analysis	Transient and small-signal stability findings.	Stability findings often produce uncoordinated affected systems coordination.
7	Short Circuit Analysis	Breaker duty exceedances and required upgrades.	Breaker upgrades often have multi-year lead times that affect in-service date.
8	Direct Attachment Facilities	The interconnection lead line, switchyard, and POI equipment.	Direct facilities are 100% project-cost. Land control on the lead-line corridor is critical.
9	Network Upgrades	The transmission upgrades required system-wide.	Network upgrade allocations can change between Phase I and Phase II as queue position evolves.
10	Contingent Facilities	Upgrades whose completion is required before your project can interconnect.	This is where most schedule and cost risk lives. Read every line.
11	Affected Systems	Upgrades on neighboring transmission systems.	Inter-RTO coordination adds 12 to 24 months of schedule risk.
12	Cost Summary	The full allocation table.	Verify every line; compare allocated share to identified violations.
13	Schedule	Construction lead times for each upgrade.	Long-lead transformers and reactors set the in-service date floor.
14	Risk Factors	PJM's enumerated risk language.	Often boilerplate, but new entries here flag specific concerns.
15	Appendices	Sensitivity cases, working data.	The appendices contain the model output your engineers will need.

The Cost Summary, line by line

The Cost Summary in Section 12 is the single table that drives the Decision Point I economics. Each row represents one network upgrade, contingent facility, or affected system upgrade, with five columns: facility name, total cost estimate, project's allocated share, allocation method, and responsible party.

A typical Cost Summary table looks like this:

Facility	Total Cost	Allocated Share	Allocation Method	Responsible Party
Lead line (8.5 miles, 230 kV)	$24.5 M	100%	Direct attachment	Project Developer
POI breaker upgrade	$3.8 M	100%	Direct attachment	Project Developer
Network reactor at substation A	$18.2 M	62%	Distribution factor	Project Developer (allocated)
Line rebuild, segment B	$32.0 M	15%	Distribution factor	Project Developer (allocated)
Contingent: Substation X expansion (Q-2024-***)	$45.0 M	0%	Contingent on prior queue	Other queue project
Affected system: PJM-MISO seam upgrade	$12.5 M	40%	Inter-RTO coordination	Project + MISO project
Total project allocation		$54.0 M

The headline number is the bottom row. But the more important interpretation lives in the rows above:

Direct attachment rows (100% allocated share) are non-negotiable project costs. Land control on the lead-line corridor and easements at the POI must already be in place or actively pursued.
Distribution factor allocations (partial share) may shift between Phase I and Phase II as queue position changes. A project ahead of you in the queue withdrawing can increase your allocated share by 10 to 30 percentage points.
Contingent facility rows (0% allocated share) are the silent killers. A "0%" allocation means another queue project is responsible — but if that project withdraws, your project may inherit that allocation in Phase II, or worse, lose access to the upgrade entirely.
Affected system rows (partial share) are the highest schedule risk. The neighboring RTO's process is not under PJM's control, and inter-RTO coordination delays are common.

Contingent facilities: the section everyone underreads

Section 10 (Contingent Facilities) is the most undervalued part of a Phase I report. A contingent facility is a network upgrade required for the project to interconnect at full MFO, but allocated to a higher-priority queue project. Two scenarios apply:

Prior queue project completes the upgrade on schedule. Your project benefits without paying for it. This is the favorable case.
Prior queue project withdraws or delays. Your project either inherits the allocation (cost shifts to you in Phase II) or loses the ability to interconnect at full MFO until the upgrade is built.

The Phase I report does not predict which scenario will occur. The developer must do the contingency analysis themselves: pull each contingent facility's prior queue project, evaluate that project's site control coverage and study readiness, and assess the probability of withdrawal. A contingent facility tied to a project with weak site control is a contingent facility you should expect to inherit.

Affected systems: the schedule risk that is not on your timeline

Section 11 (Affected Systems) covers upgrades on transmission systems that are not part of PJM — typically neighboring RTOs (MISO, NYISO, ERCOT for SE Texas-adjacent regions) or non-PJM utilities. These upgrades follow the affected system's own study and construction process, which is independent of PJM's schedule.

The most common affected system patterns for Cycle 1 are:

PJM-MISO seam upgrades. Required for projects in the AEP and ComEd zones whose flow patterns affect MISO's transmission system. MISO's process adds 12 to 18 months.
PJM-NYISO interface flows. Required for projects in the PSEG, JCPL, and Met-Ed zones. NYISO's class year process can add 18 to 24 months.
Local distribution-tied affected systems. Required for projects on legacy distribution-class circuits that have been upgraded to transmission. These are governed by the relevant transmission owner's local process.

Affected system schedule risk does not appear on the PJM critical path because it is not on PJM's timeline. The developer must build the affected system process timeline into their own in-service date estimate, and accept that PJM will not be the schedule bottleneck for these upgrades.

The TC1 baseline: what advancing looks like

Transition Cycle 1 was the first cycle PJM ran under the cycle process, and its results are the only public benchmark for Cycle 1 expectations. Three TC1 statistics are particularly useful for interpreting your Cycle 1 Phase I result:

~35% of TC1 capacity advanced past Phase I. Two-thirds of TC1 capacity withdrew at DP1 or before. Withdrawal is not failure — it is a routine outcome of Phase I cost discovery.
Battery storage was the strongest performer at ~18% of advancing capacity. Battery's smaller footprint, faster construction, and higher MFO-to-acreage ratio drove higher advance rates.
Average allocated network upgrade cost was approximately $206/kW. Phase I results above $300/kW were correlated with TC1 withdrawals; results below $150/kW were correlated with advance to Phase II.

These statistics, combined with the published PJM announcement of TC1 study completion in September 2025, provide the empirical baseline for the Cycle 1 distribution. Modo Energy and other industry analysts have published TC1 economic analyses that disaggregate these averages by zone and technology — useful inputs for a project-specific comparison.

The TC1 distribution is right-skewed: median allocated cost is below average, but the long tail of $400/kW and higher results pulls the mean up. Your project's percentile within the TC1 distribution is the most relevant comparison.

The Decision Point I 3-question framework

Decision Point I forces a binary commitment: continue into Phase II (with additional deposits) or withdraw. The decision is rarely obvious from the cost alone. Three questions, applied in order, produce a defensible DP1 decision.

Question 1: Is the allocated cost economic at this MFO and PPA assumption?

Compute project NPV under the Phase I network upgrade cost as the lower-bound interconnection cost. Run sensitivity on PPA price (LMP, capacity, REC) and on MFO degradation (battery capacity fade, solar irradiance variance, wind capacity factor). If NPV is negative under base-case PPA assumptions and positive under upside, the project is on the margin and Question 2 becomes determinative.

Question 2: What is the contingent facility exposure?

Pull every contingent facility row. For each, identify the prior queue project responsible, evaluate that project's site control coverage and study readiness, and estimate the probability of withdrawal. If 30%+ of your project's MFO depends on contingent facilities tied to projects with weak site control, your effective cost (allocated + contingent inheritance) may be 1.3 to 2x the Phase I headline.

Question 3: What is the affected system schedule risk?

For each affected system entry, identify the responsible neighboring RTO or utility, evaluate their study and construction timeline, and estimate the affected system in-service date. If the affected system in-service date is later than your PPA delivery deadline or your offtake counterparty's tolerance, the project may not be deliverable on schedule even if Phase I cost is favorable.

Together, the three questions produce a DP1 decision matrix:

Q1: Economic?	Q2: Low contingent risk?	Q3: Affected systems on time?	Decision
Yes	Yes	Yes	Continue to Phase II
Yes	Yes	No	Continue, but renegotiate PPA delivery date
Yes	No	Yes	Continue, with contingency reserves
Yes	No	No	Borderline — consider modification under M-14H 7.2
No	Yes	Yes	Withdraw or modify MFO downward
No	Any	Any	Withdraw

Reading the schedule section against your in-service date

Section 13 (Schedule) lists construction lead times for each network upgrade. The longest-lead item sets the floor on your project's earliest possible in-service date. In 2026, the binding constraints across PJM Phase I reports are:

500 kV transformers: 30 to 40 months lead time.
230 kV reactors: 18 to 24 months.
500 kV breakers: 24 to 30 months.
Right-of-way easements for new transmission lines: 24 to 60 months depending on landowner concentration and PUC permitting.

If the schedule section identifies any of these as a critical-path item and your offtake delivery date is shorter than the listed lead time, the in-service date is not achievable on schedule. The DP1 decision must factor this in — either accept the slip and renegotiate the PPA, or modify the request to a smaller MFO that does not trigger the long-lead upgrade.

Modifications under Manual 14H Section 7.2

If Phase I results are unfavorable but the project is real, the developer can modify the request at DP1 within the Section 7.2 grammar. The most common modifications are:

MFO reduction. Lowering the requested MFO can drop the project below the threshold that triggers a long-lead upgrade or a contingent facility, reducing both cost and schedule risk.
Technology change. Switching from solar to solar-plus-storage, or splitting MFO between gas and battery, can change the Phase II study profile and reduce contingent exposure.
POI change. Moving the POI to a less-constrained substation can substantially change the network upgrade allocation. POI changes are governed by Section 7.2 and may require new site control on a different lead-line corridor.

Modifications are evaluated against the Section 7.2 baseline. New parcels added during modification must satisfy 7.2.2 (adjacent or recorded easement). MFO reductions and POI changes within the existing Site footprint are generally permitted; the boundary between modification and reapplication is whether the new request can be studied under the existing ASA or requires a new application.

Glossary

Phase I System Impact Study (SIS) — The first engineering study in the cycle process. Quantifies network upgrades and produces the allocated cost.
Phase II — The second engineering study, run only on projects that elect to continue at DP1.
Decision Point I (DP1) — The first formal go/no-go milestone in the cycle, triggered by Phase I results.
Decision Point II (DP2) — The second go/no-go milestone, triggered by Phase II results.
Decision Point III (DP3) — The final commitment milestone before IA execution.
MFO — Maximum Facility Output. The peak generation capacity of the facility.
POI — Point of Interconnection. The physical point at which the project connects to the PJM transmission system.
Direct Attachment Facilities — Equipment between the project and the POI: lead line, switchyard, breakers. 100% project cost.
Network Upgrades — Transmission system upgrades required by the new generation. Allocated by distribution factor.
Contingent Facilities — Upgrades required for the project but allocated to a higher-priority queue project.
Affected Systems — Upgrades on neighboring transmission systems outside PJM.
Cost Summary — Section 12 table showing per-facility cost allocation.
Distribution Factor — The percentage allocation method used when multiple projects share an upgrade.
Allocated Share — The percentage of an upgrade's cost assigned to the requesting project.
Study Deposit — The deposit posted at application that funds the Phase I and Phase II studies.
Readiness Deposit — The deposit posted at DP2 (and refunded at COD) demonstrating commercial readiness.
ASA — Application and Studies Agreement. Governs participation in the cycle process.
WMPA — Wholesale Market Participation Agreement.
GIA — Generator Interconnection Agreement, the executed agreement at the end of the cycle.
TC1 — Transition Cycle 1, the first cycle run under the cycle process. Empirical baseline for Cycle 1 expectations.

What to do this week if your Phase I report is in

Read sections 10, 11, and 12 first. Contingent facilities, affected systems, and Cost Summary contain the DP1 risk. Save the executive summary for last.
Build the contingent facility map. For every contingent facility, identify the prior queue project and assess withdrawal risk.
Compute affected system in-service date. Pull every affected system entry and apply the neighboring RTO's published timeline.
Run the 3-question framework with your finance team. Q1 economics, Q2 contingent exposure, Q3 affected system schedule. The decision matrix produces the DP1 election.
Inventory the lead-line corridor site control. Direct attachment facilities are 100% project cost. If the lead line crosses parcels you do not control, that is the highest-priority cure work between now and DP1.

Sources

PJM Manual 14H — Sections 7.2 (modifications) and 8 (Phase I)
PJM Manual 14C — Network upgrade construction
PJM Tariff, Part VII, Subpart B — Cycle process anchor
PJM — September 2025 announcement of TC1 study completion
Modo Energy — TC1 economic analysis (zone- and technology-disaggregated)
FERC Order 2023, Interconnection Final Rule explainer
PJM Interconnection Process Subcommittee — education materials