ER26-3515-002 · 2026-11-09 · PJM

Thirty-Day Compliance Filing on PJM’s Large Load Definition and Large Load Registry

Read topic-matched comments in ER26-3515

Topics in the text: Registry access · Connecting load and generation · Reliability and curtailment

What the document says

Registry scope · PDF pp. 1–2

Transmittal: what survived the October order

PJM asks for an October 12 effective date for the definition and registry. It strips out the two fields that would have recorded a customer's new capacity and allocated backstop megawatts. The filing does not revive the rejected curtailment service.

the amount of BYONC brought by a particular Large Load and the allocated RBP UCAP MW quantity PDF p. 2

A registry cannot tell an operator what just tripped

Independent Market Monitor for PJM · Related public statement

The market monitor distinguished enrollment data from real-time telemetry. It said PJM had not shown how it would measure an actual reduction in the proposed interim service.

PDF p. 18, ¶40

States supported the registry while challenging a different payment rule

Organization of PJM States · Related public statement

OPSI supported the registry because states need verified data to allocate retail costs and decide how to curtail load. Its separate objection concerned automatically compensating curtailed projects. Three commissions abstained on the combined comments; that is not a vote against the registry.

PDF pp. 1, 7–10, footnote 2 and sections I.D–III

A separate registry was one remedy Google had sought

Google · Related public statement

In the original proceeding Google argued that FERC could accept the registry without accepting the remaining interim-service terms. This predates PJM’s compliance filing implementing that separation.

PDF p. 16, ¶36, citing Google protest pp. 3, 18

Filed comments: Registry access

Filing record · PDF pp. 2–5

I–III. What PJM submitted and served

PJM submits the same tariff and reliability agreement changes in marked and clean copies. The service section says PJM notified its members and state utility commissions. The conclusion asks for acceptance; it does not establish that FERC accepted this filing.

PJM respectfully requests that the Commission accept this compliance filing PDF p. 4

Registry scope · PDF pp. 6–65

Attachment A: how to read the marked text

The redlines show where PJM placed the surviving definition and reporting rules. Use the clean copy starting on PDF page 66 to read the resulting language; the reproduced definitions surrounding the edits are not all new rules.

all affiliated load facilities within a one-mile radius will be considered a single electrical site PDF p. 49

Registry scope · PDF pp. 66–86

Attachment B: tariff definition

The clean Open Access Transmission Tariff points to the Reliability Assurance Agreement for the definition. Page 109 gives the threshold and the test for grouping affiliated facilities.

“Large Load” shall have the meaning provided in the Reliability Assurance Agreement. PDF p. 68

Registry reporting · PDF pp. 87–90

Attachment DD-4: who keeps the registry

PJM maintains the registry under Schedule 11. Electric distributors coordinate with PJM and supply information they consider appropriate, including applicable retail tariffs and contracts. Section I is reserved.

any information or data the Electric Distributor believes appropriate to facilitate an accurate Large Load Registry PDF p. 89

States need usable records to set retail rules

Organization of PJM States · Related public statement

OPSI wanted meaningful state access to the registry to set retail curtailment rules and allocate costs. Its September comments distinguish the registry, which it supported, from the compensation mechanism it challenged.

PDF p. 7, section I.D

Filed comments: Registry access

Registry scope · PDF pp. 91–122

RAA Article 1: what counts as one site

The threshold is 50 MW of cumulative peak demand at one electrical site, even behind several interconnection points. Affiliated load facilities within a one-mile radius count as one site under the stated configurations.

a cumulative peak load of 50 megawatts or greater at a single electrical site behind one or more points of interconnection PDF p. 109

Registry reporting · PDF pp. 123–124

Schedule 11.B.1(a): what must be reported

Entities bound by the Operating Agreement must submit, or arrange submission of, data about each large load they serve. Fields include location, dates for each load increment, peak MW and ramp schedule, telemetry, and backup generation with fuel and permit limits.

Backup generation (MW), including fuel type and relevant permitting limitations PDF p. 124

Pennsylvania asks to see curtailment data

Pennsylvania Public Utility Commission · Related public statement

Pennsylvania’s commission supported creating a registry but wanted state commissions to have access and wanted PJM to record curtailments. Its comments addressed the proposal before FERC rejected interim curtailment service.

PDF p. 8, section II, Large Load Registry

Who answers for a supplier’s data?

Southern Maryland Electric Cooperative · Related public statement

The cooperative asked who bears liability when a distributor reports information obtained from another party, how it could recover its compliance costs, and whether the reporting manual would be filed for review.

PDF pp. 16–17, ¶37

Registry access · PDF p. 124

Schedule 11.B.1(b)–(d): validation and access

PJM may check the data with the distributor, transmission owner or customer. The text names regulators, system participants and the market monitor as possible recipients under safeguards. It does not explicitly list state consumer advocate offices.

Information maintained in the Large Load registry may be available to Authorized Commissions PDF p. 124

Ohio wants a seat for consumer advocates

Office of the Ohio Consumers’ Counsel · Related public statement

Ohio’s consumer advocate asked FERC to give state consumer offices the same confidential access available to commissions. Customers need an advocate who can test costs and curtailment decisions, it argued. Its November 9 request challenges the October order. It does not ask PJM to publish customer records.

PDF pp. 14, 18–19

Give customers a chance to correct errors

Equinix and PJM industrial customers · Related public statement

Equinix wanted customers notified and allowed to verify or correct the information PJM would use. Industrial customers also requested an appeal and safeguards for commercial data.

PDF p. 17, ¶38

Filed comments: Registry access

Registry access · PDF p. 124

Schedule 11.B.1(e): what the public can see

PJM would post aggregate data by distributor zone or area where possible. Confidentiality protections still apply; this is not a public list of individual sites and contracts.

aggregated by Electric Distributor zone/area, where possible PDF p. 124

Aggregate figures or individual projects?

Rep. Frank Pallone Jr. (New Jersey) · Related public statement

Pallone wanted as much of the registry made public as possible to improve demand forecasts. FERC records his request separately from the states’ requests for protected access. He spoke as a member of Congress.

PDF p. 18, ¶39

Registry reporting · PDF pp. 124–125

Schedule 11.B.2: deadlines and changes of supplier

For loads in service before June 1, 2027, the serving or contracted entity must report by March 1, 2027. For loads entering service on or after June 1, it must report before startup. It must promptly report later changes, including transfer of the right to serve the load.

before the in-service date of the Large Load PDF p. 125

Responses and related views

Which customers should lose power first?

Commissioner David Rosner · Related public statement

Rosner wanted voluntary demand response called first, followed by noncritical large loads before homes and other ordinary customers. He objected to keeping demand out of the capacity market forecast. His October concurrence predates the November compliance filing.

PDF pp. 55–57, Rosner concurrence

Source sections

Printed headings where available; page ranges otherwise. Open a heading to read the original passage.

Opening text p. 1
I. DESCRIPTION OF SUBMITTAL p. 2
II. SERVICE p. 3
III. CONCLUSION p. 4
CONCLUSION p. 4
CERTIFICATE OF SERVICE p. 5
Attachment A p. 6
Definitions – L – M – N p. 8
List of Approved Contractors: p. 9
Load Interest: p. 9
Load Management: p. 10
Load Ratio Share: p. 10
Load Reduction Event: p. 10
“Load Serving Charging Energy” shall mean energy that is purchased from the PJM Interchange Energy Market and stored in an Energy Storage Resource or Open-Loop Hybrid Resource for later resale to end-use load. p. 10
Load Shedding: p. 10
Local Upgrades: p. 10
“Long-lead Project” shall have the same meaning provided in the Operating Agreement. p. 12
Long-Term Firm Point-To-Point Transmission Service: p. 12
Loss Price: p. 12
Attachment K-Appendix, section 2. p. 12
Market Monitoring Unit Advisory Committee or MMU Advisory Committee: p. 13
Market Operations Center: p. 13
Market Participant Energy Injection: p. 14
Market Participant Energy Withdrawal: p. 14
Material Modification: p. 15
Maximum Emergency: p. 15
Maximum Facility Output: p. 15
Maximum Generation Emergency: p. 15
Maximum Generation Emergency Alert: p. 15
Maximum Run Time: p. 16
“Maximum Run Time” shall mean the maximum number of hours a generating unit can run over the course of an Operating Day, as measured by PJM’s State Estimator. p. 16
“Maximum State of Charge” shall mean the maximum State of Charge that should not be exceeded, measured in units of megawatt-hours. p. 16
Maximum Weekly Starts: p. 16
“Maximum Weekly Starts” shall mean the maximum number of times that a generating unit can be started in one week, defined as the 168 hour period starting Monday 0001 hour, under normal operating conditions. p. 16
Merchant A.C. Transmission Facilities: p. 16
Merchant D.C. Transmission Facilities: p. 16
Merchant Network Upgrades: p. 16
Merchant Transmission Facilities: p. 16
Merchant Transmission Provider: p. 17
Metering Equipment: p. 17
Minimum Generation Emergency: p. 18
“Multi-Driver Project” shall have the same meaning provided in the Operating Agreement. p. 19
Native Load Customers: p. 19
Near-Term Transmission Service: p. 19
NERC: p. 19
NERC Interchange Distribution Calculator: p. 20
Network Customer: p. 20
Network Integration Transmission Service: p. 21
Network Load: p. 21
Network Operating Agreement: p. 21
Network Operating Committee: p. 21
Network Resource: p. 21
Network Service User: p. 21
Network Transmission Service: p. 21
Network Upgrades: p. 22
New PJM Zone(s): p. 23
New Service Customers: p. 23
New Service Request: p. 23
New Services Queue: p. 23
No-load Cost: p. 23
Nominal Rated Capability: p. 24
Non-Firm Point-To-Point Transmission Service: p. 24
Non-Firm Sale: p. 25
Non-Firm Transmission Withdrawal Rights: p. 25
Non-Retail Behind The Meter Generation: p. 25
Non-Synchronized Reserve: p. 26
Non-Synchronized Reserve Event: p. 26
“Non-Variable Loads” shall have the meaning specified in Operating Agreement, Schedule 1, section 1.5A.6, and the parallel provisions of Tariff, Attachment K-Appendix, section 1.5A.6. p. 26
Non-Zone Network Load: p. 26
Normal Maximum Generation: p. 26
Normal Minimum Generation: p. 26
III. RESPONSBILITIES OF ELECTRIC DISTRIBUTORS p. 29
II. RESPONSBILITIES OF THE OFFICE OF THE INTERCONNECTION p. 30
ARTICLE 1 – DEFINITIONS p. 32
Agreement: p. 32
“Accredited UCAP” shall mean the quantity of Unforced Capacity, as denominated in Effective UCAP, that an ELCC Resource is capable of providing in a given Delivery Year. p. 32
Accredited UCAP Factor: p. 32
“Accredited UCAP Factor” shall mean, through the 2024/2025 Delivery Year, one minus EFORd, and for 2025/2026 Delivery Year and subsequent Delivery Years, the ratio of the Capacity Resource’s Accredited UCAP to the Capacity Resource’s installed capacity. p. 32
Behind The Meter Generation: p. 33
Black Start Capability: p. 34
Capacity Emergency Transfer Objective (CETO): p. 34
Capacity Emergency Transfer Limit (CETL): p. 34
“Capacity Performance Resource” shall have the same meaning as in Tariff, Attachment DD. p. 36
Capacity Resources: p. 36
Capacity Transfer Right: p. 36
Consolidated Transmission Owners Agreement, PJM Transmission Owners Agreement or Transmission Owners Agreement: p. 37
Control Area: p. 37
Daily Unforced Capacity Obligation: p. 38
Delivery Year: p. 38
Demand Resource (DR): p. 38
Demand Resource Factor or DR Factor: p. 38
Demand Resource Sell Offer Plan: p. 39
Electric Cooperative: p. 41
Electric Distributor: p. 41
Emergency: p. 41
End-Use Customer: p. 41
Energy Efficiency Resource: p. 42
Existing Demand Resource: p. 42
Facilities Study Agreement: p. 43
FERC or Commission: p. 43
Firm Point-To-Point Transmission Service: p. 43
Firm Service Level: p. 43
Firm Transmission Service: p. 44
Fixed Resource Requirement Alternative or FRR Alternative: p. 44
Forecast Pool Requirement: p. 44
FRR Capacity Plan or FRR Plan: p. 44
FRR Entity: p. 44
FRR Service Area: p. 44
Full Requirements Service: p. 45
Generation Capacity Resource: p. 46
Generation Owner: p. 46
Generator Forced Outage: p. 46
Generator Maintenance Outage: p. 47
Generator Planned Outage: p. 47
Good Utility Practice: p. 47
Incremental Auction: p. 48
IOU: p. 48
Load Serving Entity or LSE: p. 49
Locational Reliability Charge: p. 50
Markets and Reliability Committee: p. 50
Maximum Emergency Service Level: p. 50
Member: p. 50
Members Committee: p. 50
NERC: p. 50
Network Transmission Service: p. 51
Nominal PRD Value: p. 51
Nominated Demand Resource Value: p. 51
Non-Retail Behind the Meter Generation: p. 51
Obligation Peak Load: p. 51
Office of the Interconnection: p. 51
Operating Agreement of the PJM Interconnection, L.L.C., Operating Agreement or PJM Operating Agreement: p. 52
Operating Reserve: p. 52
Other Supplier: p. 53
Partial Requirements Service: p. 53
Party: p. 53
Percentage Internal Resources Required: p. 54
PJM: p. 54
PJM Board: p. 54
PJM Manuals: p. 54
PJM Region: p. 54
PJM Region Installed Reserve Margin: p. 54
PJM Tariff, Tariff, O.A.T.T., OATT or PJM Open Access Transmission Tariff: p. 55
Planned Demand Resource: p. 55
Planned External Generation Capacity Resource: p. 55
Planned Generation Capacity Resource: p. 56
Planning Period: p. 57
PRD Curve: p. 57
PRD Provider: p. 57
PRD Reservation Price: p. 57
“PRD Reservation Price” shall mean an RPM Auction clearing price identified in a PRD Plan for Price Responsive Demand load below which the PRD Provider desires not to commit the identified load as Price Responsive Demand. p. 57
PRD Substation: p. 57
Price Responsive Demand: p. 58
Price Responsive Demand Credit: p. 58
“Price Responsive Demand Credit” shall mean a credit, based on committed Price Responsive Demand, as determined under Reliability Assurance Agreement, Schedule 6.1. p. 58
Public Power Entity: p. 58
Qualifying Transmission Upgrades: p. 58
Relevant Electric Retail Regulatory Authority: p. 58
“Relevant Electric Retail Regulatory Authority” or “RERRA” shall have the meaning specified in the PJM Operating Agreement. p. 58
Reliability Principles and Standards: p. 59
Required Approvals: p. 59
Self-Supply: p. 59
State Consumer Advocate: p. 59
State Regulatory Structural Change: p. 59
Steam Class: p. 59
“Steam Class” shall mean an ELCC Class consisting of Unlimited Resources of the steam technology type and the primary fuel is not coal or nuclear. p. 60
Supervisory Control: p. 60
Threshold Quantity: p. 60
Transmission Owner: p. 61
Unforced Capacity: p. 61
Winter Peak Load (or WPL): p. 62
Zonal Capacity Price: p. 62
Zone or Zonal: p. 62
Zonal Winter Weather Adjustment Factor (ZWWAF): p. 62
“Zonal Winter Weather Adjustment Factor” or “ZWWAF” shall mean the PJM zonal winter weather normalized coincident peak divided by PJM zonal average of 5 coincident peak loads in December through February. p. 62
SCHEDULE 11 DATA SUBMITTALS p. 63
A. To perform the studies required to determine the Forecast Pool Requirement and Daily p. 63
Attachment B p. 66
Definitions – L – M – N p. 68
List of Approved Contractors: p. 69
Load Interest: p. 69
Load Management: p. 70
Load Ratio Share: p. 70
Load Reduction Event: p. 70
“Load Serving Charging Energy” shall mean energy that is purchased from the PJM Interchange Energy Market and stored in an Energy Storage Resource or Open-Loop Hybrid Resource for later resale to end-use load. p. 70
Load Shedding: p. 70
Local Upgrades: p. 70
“Long-lead Project” shall have the same meaning provided in the Operating Agreement. p. 72
Long-Term Firm Point-To-Point Transmission Service: p. 72
Loss Price: p. 72
Attachment K-Appendix, section 2. p. 72
Market Monitoring Unit Advisory Committee or MMU Advisory Committee: p. 73
Market Operations Center: p. 73
Market Participant Energy Injection: p. 74
Market Participant Energy Withdrawal: p. 74
Material Modification: p. 75
Maximum Emergency: p. 75
Maximum Facility Output: p. 75
Maximum Generation Emergency: p. 75
Maximum Generation Emergency Alert: p. 75
Maximum Run Time: p. 76
“Maximum Run Time” shall mean the maximum number of hours a generating unit can run over the course of an Operating Day, as measured by PJM’s State Estimator. p. 76
“Maximum State of Charge” shall mean the maximum State of Charge that should not be exceeded, measured in units of megawatt-hours. p. 76
Maximum Weekly Starts: p. 76
“Maximum Weekly Starts” shall mean the maximum number of times that a generating unit can be started in one week, defined as the 168 hour period starting Monday 0001 hour, under normal operating conditions. p. 76
Merchant A.C. Transmission Facilities: p. 76
Merchant D.C. Transmission Facilities: p. 76
Merchant Network Upgrades: p. 76
Merchant Transmission Facilities: p. 76
Merchant Transmission Provider: p. 77
Metering Equipment: p. 77
Minimum Generation Emergency: p. 78
“Multi-Driver Project” shall have the same meaning provided in the Operating Agreement. p. 79
Native Load Customers: p. 79
Near-Term Transmission Service: p. 79
NERC: p. 79
NERC Interchange Distribution Calculator: p. 80
Network Customer: p. 80
Network Integration Transmission Service: p. 81
Network Load: p. 81
Network Operating Agreement: p. 81
Network Operating Committee: p. 81
Network Resource: p. 81
Network Service User: p. 81
Network Transmission Service: p. 81
Network Upgrades: p. 82
New PJM Zone(s): p. 83
New Service Customers: p. 83
New Service Request: p. 83
New Services Queue: p. 83
No-load Cost: p. 83
Nominal Rated Capability: p. 84
Non-Firm Point-To-Point Transmission Service: p. 84
Non-Firm Sale: p. 85
Non-Firm Transmission Withdrawal Rights: p. 85
Non-Retail Behind The Meter Generation: p. 85
Non-Synchronized Reserve: p. 86
Non-Synchronized Reserve Event: p. 86
“Non-Variable Loads” shall have the meaning specified in Operating Agreement, Schedule 1, section 1.5A.6, and the parallel provisions of Tariff, Attachment K-Appendix, section 1.5A.6. p. 86
Non-Zone Network Load: p. 86
Normal Maximum Generation: p. 86
Normal Minimum Generation: p. 86
III. RESPONSBILITIES OF ELECTRIC DISTRIBUTORS p. 89
II. RESPONSBILITIES OF THE OFFICE OF THE INTERCONNECTION p. 90
ARTICLE 1 – DEFINITIONS p. 92
Agreement: p. 92
“Accredited UCAP” shall mean the quantity of Unforced Capacity, as denominated in Effective UCAP, that an ELCC Resource is capable of providing in a given Delivery Year. p. 92
Accredited UCAP Factor: p. 92
“Accredited UCAP Factor” shall mean, through the 2024/2025 Delivery Year, one minus EFORd, and for 2025/2026 Delivery Year and subsequent Delivery Years, the ratio of the Capacity Resource’s Accredited UCAP to the Capacity Resource’s installed capacity. p. 92
Behind The Meter Generation: p. 93
Black Start Capability: p. 94
Capacity Emergency Transfer Objective (CETO): p. 94
Capacity Emergency Transfer Limit (CETL): p. 94
“Capacity Performance Resource” shall have the same meaning as in Tariff, Attachment DD. p. 96
Capacity Resources: p. 96
Capacity Transfer Right: p. 96
Consolidated Transmission Owners Agreement, PJM Transmission Owners Agreement or Transmission Owners Agreement: p. 97
Control Area: p. 97
Daily Unforced Capacity Obligation: p. 98
Delivery Year: p. 98
Demand Resource (DR): p. 98
Demand Resource Factor or DR Factor: p. 98
Demand Resource Sell Offer Plan: p. 99
Electric Cooperative: p. 101
Electric Distributor: p. 101
Emergency: p. 101
End-Use Customer: p. 101
Energy Efficiency Resource: p. 102
Existing Demand Resource: p. 102
Facilities Study Agreement: p. 103
FERC or Commission: p. 103
Firm Point-To-Point Transmission Service: p. 103
Firm Service Level: p. 103
Firm Transmission Service: p. 104
Fixed Resource Requirement Alternative or FRR Alternative: p. 104
Forecast Pool Requirement: p. 104
FRR Capacity Plan or FRR Plan: p. 104
FRR Entity: p. 104
FRR Service Area: p. 104
Full Requirements Service: p. 105
Generation Capacity Resource: p. 106
Generation Owner: p. 106
Generator Forced Outage: p. 106
Generator Maintenance Outage: p. 107
Generator Planned Outage: p. 107
Good Utility Practice: p. 107
Incremental Auction: p. 108
IOU: p. 108
Load Serving Entity or LSE: p. 109
Locational Reliability Charge: p. 110
Markets and Reliability Committee: p. 110
Maximum Emergency Service Level: p. 110
Member: p. 110
Members Committee: p. 110
NERC: p. 110
Network Transmission Service: p. 111
Nominal PRD Value: p. 111
Nominated Demand Resource Value: p. 111
Non-Retail Behind the Meter Generation: p. 111
Obligation Peak Load: p. 111
Office of the Interconnection: p. 111
Operating Agreement of the PJM Interconnection, L.L.C., Operating Agreement or PJM Operating Agreement: p. 112
Operating Reserve: p. 112
Other Supplier: p. 113
Partial Requirements Service: p. 113
Party: p. 113
Percentage Internal Resources Required: p. 114
PJM: p. 114
PJM Board: p. 114
PJM Manuals: p. 114
PJM Region: p. 114
PJM Region Installed Reserve Margin: p. 114
PJM Tariff, Tariff, O.A.T.T., OATT or PJM Open Access Transmission Tariff: p. 115
Planned Demand Resource: p. 115
Planned External Generation Capacity Resource: p. 115
Planned Generation Capacity Resource: p. 116
Planning Period: p. 117
PRD Curve: p. 117
PRD Provider: p. 117
PRD Reservation Price: p. 117
“PRD Reservation Price” shall mean an RPM Auction clearing price identified in a PRD Plan for Price Responsive Demand load below which the PRD Provider desires not to commit the identified load as Price Responsive Demand. p. 117
PRD Substation: p. 117
Price Responsive Demand: p. 118
Price Responsive Demand Credit: p. 118
“Price Responsive Demand Credit” shall mean a credit, based on committed Price Responsive Demand, as determined under Reliability Assurance Agreement, Schedule 6.1. p. 118
Public Power Entity: p. 118
Qualifying Transmission Upgrades: p. 118
Relevant Electric Retail Regulatory Authority: p. 118
“Relevant Electric Retail Regulatory Authority” or “RERRA” shall have the meaning specified in the PJM Operating Agreement. p. 118
Reliability Principles and Standards: p. 119
Required Approvals: p. 119
Self-Supply: p. 119
State Consumer Advocate: p. 119
State Regulatory Structural Change: p. 119
Steam Class: p. 119
“Steam Class” shall mean an ELCC Class consisting of Unlimited Resources of the steam technology type and the primary fuel is not coal or nuclear. p. 120
Supervisory Control: p. 120
Threshold Quantity: p. 120
Transmission Owner: p. 121
Unforced Capacity: p. 121
Winter Peak Load (or WPL): p. 122
Zonal Capacity Price: p. 122
Zone or Zonal: p. 122
Zonal Winter Weather Adjustment Factor (ZWWAF): p. 122
“Zonal Winter Weather Adjustment Factor” or “ZWWAF” shall mean the PJM zonal winter weather normalized coincident peak divided by PJM zonal average of 5 coincident peak loads in December through February. p. 122
SCHEDULE 11 DATA SUBMITTALS p. 123
A. To perform the studies required to determine the Forecast Pool Requirement and Daily p. 123