Invoice number is comprised of year, month, day and customer ID#
Customer Account's long name
Customer account's short name followed by Customer ID#
Time at which the billing statement was posted in MSRS
Start and end dates of the billing period
Network customers pay daily demand charges to PJM transmission owners using the applicable zonal or non-zone Network Integration Transmission Service rates. All network customers in the AP zone receive rebates to hold them harmless from the network rate conversion upon PJM integration. For transmission owners (except those in ATSI, PPL, ComEd, Dayton, Duke, and Duquesne zones), the charges for their own transmission facilities are not actually paid (i.e., exempted with an equal amount credits) and are shown only to identify their cost responsibility as ordered by FERC.
For more information, visit the
Guide to Billing.
All network customers and merchant transmission owners pay transmission owners for required transmission enhancement projects in accordance with the zonal cost responsibility allocations in the appendix to Schedule 12. All transmission projects collecting these payments are on PJM’s website under Transmission Services/Formula Rates.
For more information, visit the
Guide to Billing.
Firm point-to-point transmission customers pay demand charges for reserved capacity at the applicable tariff rates based on the term of the reservations. There is no charge for reserved capacity with a MISO point of delivery.
For more information, visit the
Guide to Billing.
Non-firm point-to-point transmission customers pay demand charges for reserved capacity at the discounted rate. There is no charge for reserved capacity with a MISO point of delivery.
For more information, visit the
Guide to Billing.
Net Day-ahead Spot Market energy positions are charged at the PJM-wide day-ahead system energy price for each hour. Charges are positive for energy purchased from the PJM Spot Market (i.e. energy withdrawals) and negative for energy delivered to the PJM Spot Market (i.e. energy injections)and totals are summed for each hour.
For more information, visit the
Guide to Billing.
Net real-time deviations from day-ahead energy positions are charged at one-twelfth the PJM-wide real-time system energy price for each five minute interval. In situations where five minute energy position interval data has not been provided (including all day-ahead energy position data), the energy position value provided will be scaled or flat-profiled across each of the five minute intervals of the provided period in order to obtain five minute interval energy positions and deviations. Charges may be positive or negative depending on the direction of the real-time deviation from the day-ahead energy position, and totals are summed for each hour.
For more information, visit the
Guide to Billing.
Day-ahead Implicit Congestion charges are calculated hourly as the sum of day-ahead withdrawal values (i.e., all cleared day-ahead demand/decrement/load response bids and sale transactions priced at the applicable locations’ day-ahead congestion prices) minus the sum of day-ahead injection values (i.e., all cleared day-ahead generation/increment offers and purchase transactions priced at the applicable locations’ day-ahead congestion prices).
Explicit Congestion charges for day-ahead energy transactions are calculated hourly and equal the scheduled MWh times the difference between day-ahead sink and source congestion prices. These charges are assessed to the buyer (or point-to-point transmission customer, if applicable).
For more information, visit the
Guide to Billing.
For planning years in which the sum of actual Transmission Congestion credits paid to FTR holders during the planning year was less than the sum of their FTR Targets, Planning Period Congestion Uplift credits are awarded to the FTR holders at the end of the planning year (May) to completely fulfill those remaining FTR Target deficiencies. Planning Period Congestion Uplift credits and Planning Period Congestion Uplift charges can only occur at the end of the Annual Planning Period (which runs from June 1st through May 31st), so they will only apply to May monthly billing statements.
For more information, visit the
Guide to Billing.
Balancing Implicit Congestion charges are calculated for each five minute interval as the sum of balancing withdrawal congestion values (i.e., all deviations between demand/decrement/load response bids and sale transactions cleared day-ahead versus real-time load without losses, and sale transactions, priced at one-twelfth of the applicable locations’ real-time congestion prices) minus the sum of balancing injection congestion values (i.e., all deviations between generation/increment offers and purchase transactions cleared day-ahead versus real-time generation and purchase transactions, priced at one-twelfth of the applicable locations’ real-time congestion prices). In situations where five minute energy position interval data has not been provided (including all day-ahead energy position data), the energy position value provided will be scaled or flat-profiled across each of the five minute intervals of the provided period in order to obtain five minute interval energy positions and deviations. Charges may be positive or negative depending on the direction of the real-time deviation from the day-ahead energy position, and totals are summed for each hour.
Explicit Congestion charges for balancing energy transactions are calculated for each five minute interval and equal any real-time deviations from the transaction MWs cleared day-ahead times one-twelfth of the difference between the real-time sink and source congestion prices. In situations where five minute energy position interval data has not been provided (including all day-ahead energy position data), the energy position value provided will be flat-profiled across each of the five minute intervals of the provided period in order to obtain five minute interval energy positions and deviations. Charges may be positive or negative depending on the direction of the real-time deviation from the day-ahead energy position, and totals are summed for each hour. These charges are assessed to the buyer (or point-to-point transmission customer, if applicable).
For more information, visit the
Guide to Billing.
The increased costs of energy due to transmission losses represented in the PJM network model are assessed to market participants based on the loss component of LMPs, and the revenues collected are allocated to market participants’ serving load and delivering PJM exports (that pay for PJM transmission service).
For more information, visit the
Guide to Billing.
The increased costs of energy due to transmission losses represented in the PJM network model are assessed to market participants based on the loss component of LMPs, and the revenues collected are allocated to market participants’ serving load and delivering PJM exports (that pay for PJM transmission service).
For more information, visit the
Guide to Billing.
Charges: PJM hourly total inadvertent interchange charges (+/-) priced at the load weighted-average PJM real-time LMP and allocated based on real-time load ratio shares.
For more information, visit the
Guide to Billing.
Charges: Monthly charges (+/-) to PJM fully-metered EDCs and generators for corrections to metered energy values, with PJM Mid-Atlantic 500kV corrections allocated based on real-time load ratio shares, using the applicable generator or PJM load weighted-average real-time LMP for the month. Meter correction charges for any external PJM tie-line corrections are allocated to all LSEs based on real-time load (without losses) ratio shares. Effective February 2010, EDCs may elect to have their charges (+/-) directly allocated by PJM to LSEs in their zone based on load ratio shares if all LSEs in the EDC territory concur.
For more information, visit the
Guide to Billing.
PJM emergency energy transactions (made on behalf of market participants) are priced at 150% of LMP at the appropriate PJM interface in accordance with the PJM agreements with adjacent control areas.
For more information, visit the
Guide to Billing.
Monthly formula rate is charged to transmission customers based on their usage of the PJM transmission system. Monthly transmission use (in MWh) includes network customers’ real-time load and point-to-point customers’ real-time energy use.
For more information, visit the
Guide to Billing.
Component 1: Monthly formula rate is charged to FTR holders based on FTR MW and hours each FTR is in effect (regardless of congested hours and dollar value of FTR). Component 2: Monthly formula rate is charged to FTR Auction participants based on the number of hours associated with each FTR obligation bid submitted in an FTR Auction (this rate is multiplied by 5 for FTR options).
For more information, visit the
Guide to Billing.
Component 1: Monthly formula rate is charged to transmission customers based on their network load and exports, to providers of generation and imports, and to day-ahead energy market participants based on their accepted increment offers, decrement bids, and up-to congestion bids. Component 2: Monthly formula rate is charged for each energy bid/offer segment price/quantity pair submitted, including those submitted during the rebidding period.
For more information, visit the
Guide to Billing.
2021 rate of $0.3035/Regulation MWh (with $0.00 refund rate for 4Q2021) charged to customers based on regulation obligation and regulation provided.
For more information, visit the
Guide to Billing.
Monthly formula rate is charged to LSEs based on their daily unforced capacity obligations and to capacity resource owners based on their daily unforced capacity (including FRRs).
For more information, visit the
Guide to Billing.
This rate has been terminated.
For more information, visit the
Guide to Billing.
4Q2021 rate of $0.0039/MWh refunded to transmission customers based on their network load and exports, to providers of generation and imports, and to day-ahead energy market participants based on their accepted increment offers, decrement bids, and up-to congestion bids to reflect the reimbursement made to offset the PJM Settlement, Inc. charges.
For more information, visit the
Guide to Billing.
2021 rate of $0.2262/MWh (with $0.0388 refund rate for 4Q2021) charged to transmission customers based on their usage of the PJM transmission system. Monthly transmission use (in MWh) includes network customers’ real-time load and point-to-point customers’ real-time energy use.
For more information, visit the
Guide to Billing.
2021 rate of $0.0030/FTR MWh (with $0.0024/FTR MWh refund for 4Q2021) charged to FTR holders based on FTR MW and hours each FTR is in effect (regardless of congested hours and dollar value of FTR). 2021 rate of $0.0020/bid-hour (with $0.0020 refund rate for 4Q2021) charged to FTR Auction participants based on the number of hours associated with each FTR obligation bid submitted in an FTR Auction (this rate is multiplied by 5 for FTR options).
For more information, visit the
Guide to Billing.
2021 rate of $0.0499/MWh (with $0.00 refund rate for 4Q2021) charged to transmission customers based on their network load and exports, to providers of generation and imports, and to day-ahead energy market participants based on their accepted increment offers, decrement bids, and up-to congestion bids. 2021 rate of $0.0746 (with $0.0729 refund rate for 4Q2021) is charged for each energy bid/offer segment price/quantity pair submitted, including those submitted during the rebidding period.
For more information, visit the
Guide to Billing.
2021 rate of $0.3035/Regulation MWh (with $0.00 refund rate for 4Q2021) charged to customers based on regulation obligation and regulation provided.
For more information, visit the
Guide to Billing.
2021 rate of $0.1156/MW-day (with $0.0413 refund rate for 4Q2021) charged to LSEs based on their daily unforced capacity obligations and to capacity resource owners based on their daily unforced capacity (including FRRs).
For more information, visit the
Guide to Billing.
PJM transitioned from a stated rate to a formula rate mechanism on January 1, 2022. All amounts held in reserve
as of December 31, 2021 will be refunded within the first calendar quarter of 2022. Monthly formula rate is charged to each customer account receiving an invoice from PJM Settlement on per-invoice basis.
For more information, visit the
Guide to Billing.
Component 1: 2021 rate of $0.0063/MWh charged to transmission customers based on their network load and exports, to providers of generation and imports, and to day-ahead energy market participants based on their accepted increment offers, decrement bids, and up-to congestion bids. Component 2: 2021 rate of $0.0041 is charged for each energy bid/offer segment price/quantity pair submitted, including those submitted during the rebidding period.
For more information, visit the
Guide to Billing.
2021 rate of $0.0948/MWh charged to transmission customers based on their usage of the PJM transmission
system. Monthly transmission use includes network customers’ real-time load and point-to-point transmission customers’ realtime energy transactions.
For more information, visit the
Guide to Billing.
2021 rate of $0.0008/MWh charged to transmission customers based on their usage of the PJM transmission
system. Monthly transmission use includes network customers’ real-time load and point-to-point transmission customers’ realtime energy transactions.
For more information, visit the
Guide to Billing.
2021 rate of $0.0159/MWh charged to transmission customers based on their energy delivered to load in the PJM Region, excluding load in the Dominion and East Kentucky Power Cooperative zones. Each calendar year, any over or under collection of NERC’s actual costs are trued up in that year’s December billing cycle.
For more information, visit the
Guide to Billing.
2021 rate of $0.0250/MWh charged to transmission customers based on their energy delivered to load in the PJM Region, excluding load in the Dominion and East Kentucky Power Cooperative zones. Each calendar year, any over or under collection of RFC’s actual costs are trued up in that year’s December billing cycle.
For more information, visit the
Guide to Billing.
All Transmission Customers purchase this from PJM to schedule energy through, out, within, or into PJM.
For more information, visit the
Guide to Billing.
All Transmission Customers purchase this from PJM to maintain acceptable transmission voltages.
For more information, visit the
Guide to Billing.
Invoice number is comprised of year, month, day and customer ID#
Customer Account's long name
Customer account's short name followed by Customer ID#
Time at which the billing statement was posted in MSRS
Start and end dates of the billing period
PJM conducts synchronized reserve markets to ensure the capability of synchronized generation and economic load response that can be converted fully into energy within ten minutes.
For more information, visit the
Guide to Billing.
Effective October 1, 2022, Day-ahead Scheduling Reserve was removed from the PJM market. Reconciliation Charges will conclude in the December 2022 monthly bill.
For more information, visit the
Guide to Billing.
To ensure adequate operating reserve and for spot market support, pool-scheduled generation and demand resources and that operate as requested by PJM are guaranteed to fully recover their daily offer amounts.
For more information, visit the
Guide to Billing.
To ensure adequate operating reserve and for spot market support, pool-scheduled generation and demand resources and that operate as requested by PJM are guaranteed to fully recover their daily offer amounts.
For more information, visit the
Guide to Billing.
Charges: For day-ahead and real-time economic load response, the CSP’s LSE is charged the difference between LMP and the retail rate, as applicable, times the MWh reduction. For emergency load response, all balancing energy market participants are allocated charges using the same method as for PJM emergency energy purchases.
For more information, visit the
Guide to Billing.
Charges: Total daily cost of synchronous condensing (not for synchronized reserve or reactive services) is allocated based on real-time load (without losses) plus export ratio shares.
For more information, visit the
Guide to Billing.
All Transmission Customers purchase this from PJM to ensure the reliable restoration following a shut down of the PJM transmission system.
For more information, visit the
Guide to Billing.
PJM conducts annual and monthly FTR auctions for the transaction of FTRs at market clearing prices. Net auction revenues are allocated daily to ARR holders and then FTR holders as excess congestion revenues.
For more information, visit the
Guide to Billing.
Charges: Each buy bid MW cleared in the an first or third incremental auction adjusted by cleared buy bid transactions pays the applicable LDA’s resource clearing price. Resource make-whole payments for an incremental auction are also allocated as charges to Market Buyers based on these MW shares of cleared buy bids adjusted by cleared buy bid transactions MW shares for the first or third incremental auctions. Resource make-whole payments for the base residual or second incremental auctions and the portion of the resource make-whole payment for an incremental auction that would be based on PJM cleared buy bids are allocated as charges to LSEs in the applicable LDA via the Final Zonal Capacity Price.
For more information, visit the
Guide to Billing.
Charges: Each LSE is charged for their daily unforced capacity obligation priced at the applicable zonal capacity price for the delivery year.
For more information, visit the
Guide to Billing.
Bilateral capacity transactions for multi-day durations are settled in the PJM capacity markets.
For more information, visit the
Guide to Billing.
Sellers with zonal aggregate committed Demand Resources or nominated ILR that cannot demonstrate hourly real-time performance pay a penalty charge which is allocated to Demand Resource and ILR providers and, potentially, LSEs. This billing is performed on a three-month lag.
For more information, visit the
Guide to Billing.
Generation capacity resources that fail a capacity test pay this charge which is allocated to eligible LSEs. This billing is performed in the June billing cycle after the conclusion of the delivery year.
For more information, visit the
Guide to Billing.
Cleared qualifying transmission upgrades delayed in coming into service for the applicable delivery year pay a daily penalty charge which is allocated to eligible LSEs.
For more information, visit the
Guide to Billing.
Each generation capacity resource must have available unforced capacity during the peak season to satisfy its cleared MW. This billing is performed in the June billing cycle after the conclusion of the delivery year. Only applies to the month of June.
For more information, visit the
Guide to Billing.
To ensure capacity resource availability during critical peak hours, incentives are provided to resources that exceed expected availability and penalties are assessed to those who fall short. This billing is performed in the August billing cycle after the conclusion of the delivery year. Only applies to the month of August.
For more information, visit the
Guide to Billing.
Invoice number is comprised of year, month, day and customer ID#
Customer Account's long name
Customer account's short name followed by Customer ID#
Time at which the billing statement was posted in MSRS
Start and end dates of the billing period
Network customers pay daily demand charges to PJM transmission owners using the applicable zonal or non-zone Network Integration Transmission Service rates. All network customers in the AP zone receive rebates to hold them harmless from the network rate conversion upon PJM integration. For transmission owners (except those in ATSI, PPL, ComEd, Dayton, Duke, and Duquesne zones), the charges for their own transmission facilities are not actually paid (i.e., exempted with an equal amount credits) and are shown only to identify their cost responsibility as ordered by FERC.
For more information, visit the
Guide to Billing.
All network customers and merchant transmission owners pay transmission owners for required transmission enhancement projects in accordance with the zonal cost responsibility allocations in the appendix to Schedule 12. All transmission projects collecting these payments are on PJM’s website under Transmission Services/Formula Rates.
For more information, visit the
Guide to Billing.
The increased energy costs due to redispatch during the applicable interval when the PJM transmission system is constrained are assessed to market participants based on the congestion price component of LMPs. Day-Ahead revenues collected are allocated as credits to FTR holders. Balancing Revenues are allocated as credits based on real-time load plus exports ratio shares.
For more information, visit the
Guide to Billing.
For planning years in which the sum of actual Transmission Congestion credits paid to FTR holders during the planning year was less than the sum of their FTR Targets, Planning Period Congestion Uplift credits are awarded to the FTR holders at the end of the planning year (May) to completely fulfill those remaining FTR Target deficiencies. Planning Period Congestion Uplift credits and Planning Period Congestion Uplift charges can only occur at the end of the Annual Planning Period (which runs from June 1st through May 31st), so they will only apply to May monthly billing statements.
For more information, visit the
Guide to Billing.
Non-firm point-to-point transmission customers pay demand charges for reserved capacity at the discounted rate. There is no charge for reserved capacity with a MISO point of delivery.
For more information, visit the
Guide to Billing.
The increased costs of energy due to transmission losses represented in the PJM network model are assessed to market participants based on the loss component of LMPs, and the revenues collected are allocated to market participants’ serving load and delivering PJM exports (that pay for PJM transmission service).
For more information, visit the
Guide to Billing.
Day-ahead and real-time economic and real-time emergency load response credits are provided to CSPs equal to the reduced MWh times LMP (minus retail rate, as applicable).
For more information, visit the
Guide to Billing.
PJM emergency energy transactions (made on behalf of market participants) are priced at 150% of LMP at the appropriate PJM interface in accordance with the PJM agreements with adjacent control areas. Charges: Hourly net costs of emergency energy purchased by PJM are allocated to real-time deviations from day-ahead net interchange that create a shorter real-time position, except for purchases for external control areas’ MinGen Emergencies where costs are allocated to deviations that create a longer position.
For more information, visit the
Guide to Billing.
All Transmission Customers purchase this from PJM to schedule energy through, out, within, or into PJM.
For more information, visit the
Guide to Billing.
All Transmission Customers purchase this from PJM to maintain acceptable transmission voltages.
Monthly credits provided to generation and transmission owners with FERC-approved reactive revenue requirements.
For more information, visit the
Guide to Billing.
PJM conducts synchronized reserve markets to ensure the capability of synchronized generation and economic load response that can be converted fully into energy within ten minutes.
For more information, visit the
Guide to Billing.
Effective October 1, 2022, Day-ahead Scheduling Reserve was removed from the PJM market. Reconciliation Charges will conclude in the December 2022 monthly bill.
For more information, visit the
Guide to Billing.
To ensure adequate operating reserve and for spot market support, pool-scheduled generation and demand resources and that operate as requested by PJM are guaranteed to fully recover their daily offer amounts.
For more information, visit the
Guide to Billing.
Daily credits for condensing and energy use costs are calculated on a five minute interval basis and are provided to eligible synchronous condensers dispatched by PJM for purposes other than synchronized reserve, post-contingency, or reactive services.
For more information, visit the
Guide to Billing.
Generating resources whose output is altered by PJM for the purpose of maintaining reactive reliability are guaranteed to fully recover their daily offer amounts or compensated for their lost opportunity costs.
For more information, visit the
Guide to Billing.
All Transmission Customers purchase this from PJM to ensure the reliable restoration following a shut down of the PJM transmission system.
For more information, visit the
Guide to Billing.
PJM conducts annual and monthly FTR auctions for the transaction of FTRs at market clearing prices. Net auction revenues are allocated daily to ARR holders and then FTR holders as excess congestion revenues.
For more information, visit the
Guide to Billing.
Auction Revenue Rights (ARR) are entitlements to receive an allocation of net FTR auction revenues that are allocated annually and reassigned daily to network and firm point-to-point transmission customers.
For more information, visit the
Guide to Billing.
Credits: Each sell offer for generation, demand, or qualified transmission upgrade resource MW cleared in an RPM Auction is paid the applicable resource’s clearing price in the applicable auction. Resource make-whole payments are also provided to sell offers that clear less than the minimum amount specified. Sell offers are adjusted by approved unit-specific transactions for cleared capacity.
For more information, visit the
Guide to Billing.
Credits: Each ILR resource is credited for their certified zonal MW priced at the applicable zonal ILR price.
For more information, visit the
Guide to Billing.
To recognize the value of import capability to constrained LDAs, Capacity Transfer Rights (CTRs) are allocated to LSEs in those LDAs to offset their higher load charges.
For more information, visit the
Guide to Billing.
Incremental CTRs are provided to fund for transmission upgrades (not including qualifying transmission upgrades cleared in the Base Residual Auction) that increase import capability into a constrained LDA. Incremental CTRs for Incremental-Rights Eligible Required Transmission Enhancements are determined and allocated as defined in Schedule 12A of the Tariff.
For more information, visit the
Guide to Billing.
Incremental CTRs are provided to fund for transmission upgrades (not including qualifying transmission upgrades cleared in the Base Residual Auction) that increase import capability into a constrained LDA.
For more information, visit the
Guide to Billing.
Sellers with zonal aggregate committed Demand Resources or nominated ILR that cannot demonstrate hourly real-time performance pay a penalty charge which is allocated to Demand Resource and ILR providers and, potentially, LSEs. This billing is performed on a three-month lag.
For more information, visit the
Guide to Billing.
Capacity resources that are unable or unavailable to deliver unforced capacity, and do not obtain replacement unforced capacity to satisfy their cleared sell offer pay this charge which is allocated to eligible LSEs.
For more information, visit the
Guide to Billing.
Generation capacity resources that fail a capacity test pay this charge which is allocated to eligible LSEs. This billing is performed in the June billing cycle after the conclusion of the delivery year. Only applies to the month of June.
For more information, visit the
Guide to Billing.
Cleared qualifying transmission upgrades delayed in coming into service for the applicable delivery year pay a daily penalty charge which is allocated to eligible LSEs.
For more information, visit the
Guide to Billing.
Each generation capacity resource must have available unforced capacity during the peak season to satisfy its cleared MW. This billing is performed in the June billing cycle after the conclusion of the delivery year. Only applies to the month of June.
For more information, visit the
Guide to Billing.
To ensure capacity resource availability during critical peak hours, incentives are provided to resources that exceed expected availability and penalties are assessed to those who fall short. This billing is performed in the August billing cycle after the conclusion of the delivery year. Only applies to the month of August.
For more information, visit the
Guide to Billing.
Sellers with committed Demand Resources that fail performance tests pay a penalty charge which is allocated to eligible LSEs. This billing is performed in the August monthly bill issued in September after the conclusion of the Delivery Year.
For more information, visit the
Guide to Billing.
All network customers (except those in the Dominion and ATSI Zones) pay AEP, ComEd, and Dayton to recover their integration expenses. This charge is expected to continue through April 2015.
For more information, visit the
Synchronized ReserveGuide to Billing.
Credits: PJM’s share of monthly carrying charges for Ramapo Phase Angle Regulators (PARs) are credited to NYISO in accordance with the NYPP-PJM PARs Facilities Agreement.
For more information, visit the
Guide to Billing.
Non-firm point-to-point transmission customers pay demand charges for reserved capacity at the discounted rate. There is no charge for reserved capacity with a MISO point of delivery.
For more information, visit the
Guide to Billing.
Billing Adjustments - see BLI Adjustment Summary Report in MSRS for additional information on select adjustments.
For more information, visit the
Guide to Billing.
Non-firm point-to-point transmission customers pay demand charges for reserved capacity at the discounted rate. There is no charge for reserved capacity with a MISO point of delivery.
For more information, visit the
Guide to Billing.
The increased energy costs due to redispatch during the applicable interval when the PJM transmission system is constrained are assessed to market participants based on the congestion price component of LMPs. Day-Ahead revenues collected are allocated as credits to FTR holders. Balancing Revenues are allocated as credits based on real-time load plus exports ratio shares.
For more information, visit the
Guide to Billing.
Billing Adjustments - see BLI Adjustment Summary Report in MSRS for additional information on select adjustments.
For more information, visit the
Guide to Billing.
The increased energy costs due to redispatch during the applicable interval when the PJM transmission system is constrained are assessed to market participants based on the congestion price component of LMPs. Day-Ahead revenues collected are allocated as credits to FTR holders. Balancing Revenues are allocated as credits based on real-time load plus exports ratio shares.
For more information, visit the
Guide to Billing.
PJM conducts a regulation market to continuously balance generation resources with PJM load and to maintain Interconnection frequency within acceptable limits.
For more information, visit the
Guide to Billing.
Billing Adjustments - see BLI Adjustment Summary Report in MSRS for additional information on select adjustments.
For more information, visit the
Guide to Billing.
PJM conducts a regulation market to continuously balance generation resources with PJM load and to maintain Interconnection frequency within acceptable limits.
For more information, visit the
Guide to Billing.
Effective October 1, 2022, Day-ahead Scheduling Reserve was removed from the PJM market. Reconciliation Charges will conclude in the December 2022 monthly bill.
For more information, visit the
Guide to Billing.
Billing Adjustments - see BLI Adjustment Summary Report in MSRS for additional information on select adjustments.
For more information, visit the
Guide to Billing.
Effective October 1, 2022, Day-ahead Scheduling Reserve was removed from the PJM market. Reconciliation Charges will conclude in the December 2022 monthly bill.
For more information, visit the
Guide to Billing.