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Monthly Billing Statement Example
The images below show a sample PJM monthly billing statement. To learn more about a specific line item on the statement, point your mouse cursor over that item and a description will pop up. Pop-ups must be enabled in your Web browser in order to view these descriptions.
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
Total charges minus total credits
Total charges minus total credits
Amount billed month-to-date via weekly billing
Amount billed month-to-date via weekly billing
The Monthly Billing Statement Summary field will include the text “Total Net Credit to You. Please Do Not Pay.” if the customer account has a net credit for the billing period. The field will include the text “Total Net Charge. Please Pay This Amount.” if the customer account has a net charge for the billing period. The Amount field will display the amount of the net credit or net charge. This Amount value represents the difference between the Monthly Billing Total and the Previous Weekly Billing Total values.
The Monthly Billing Statement Summary field will include the text “Total Net Credit to You. Please Do Not Pay.” if the customer account has a net credit for the billing period. The field will include the text “Total Net Charge. Please Pay This Amount.” if the customer account has a net charge for the billing period. The Amount field will display the amount of the net credit or net charge. This Amount value represents the difference between the Monthly Billing Total and the Previous Weekly Billing Total values.
The TERMS: field will include the following text “PAYABLE IN FULL BY TIME EPT ON DATE”, where Time is displayed in eastern prevailing time in hh:mm AM/PM format and date is displayed in mm/dd/yyyy format.
The WIRE TRANSFER FUNDS TO: information on the report will display on five separate, consecutive lines. The WIRE TRANSFER FUNDS TO: label will appear next to the first line of data and the four subsequent lines of data will appear immediately below the first line of data without a label.
The cover page will also include an ‘Additional Billing Statement Information’ field, which will be used to communicate any special messages that may apply to that billing period’s billing statement. The text that appears in this section will not be customer account-specific. This field may be null if there is no message for the current billing period.
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, 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. Low voltage charges also apply for the ATSI zone based on their peak load contribution in each ATSI utility service territory using the applicable customer’s low voltage billing factor for each ATSI service territory.
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.
Day-ahead energy market net hourly PJM Interchange MWh are calculated for cleared day-ahead generation and increment offers, demand, decrement, and load response bids, and day-ahead energy transactions. Real-time energy market net hourly PJM Interchange MWh are calculated for real-time energy transactions, load (without losses), generation, and metered tie flows, as applicable.
For more information, visit the Guide to Billing.
Day-ahead energy market net hourly PJM Interchange MWh are calculated for cleared day-ahead generation and increment offers, demand, decrement, and load response bids, and day-ahead energy transactions. Real-time energy market net hourly PJM Interchange MWh are calculated for real-time energy transactions, load (without losses), generation, and metered tie flows, as applicable.
For more information, visit the Guide to Billing.
The increased energy costs due to redispatch during hours when the PJM transmission system is constrained are assessed to market participants based on the congestion price component of LMPs, and the revenues collected are allocated to FTR holders.
For more information, visit the Guide to Billing.
The increased energy costs due to redispatch during hours when the PJM transmission system is constrained are assessed to market participants based on the congestion price component of LMPs, and the revenues collected are allocated to FTR holders.
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.
2012 rate of $0.1692/MWh (with $0.0072 refund rate for Apr-Jun) 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.
2012 rate of $0.0025/FTR MWh (with $0.0001 refund rate for Apr-Jun) charged to FTR holders based on FTR MW and hours each FTR is in effect (regardless of congested hours and dollar value of FTR). 2012 rate of $0.0017/bid-hour (with $0.0001 refund rate for Apr-Jun) 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.
2012 rate of $0.0373/MWh (with $0.0016 refund rate for Apr-Jun) 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. 2012 rate of $0.0558 (with $0.0014 refund rate for Apr-Jun) 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.
2012 rate of $0.2271/Regulation MWh (with $0.0111 refund rate for Apr-Jun) charged to customers based on regulation obligation and regulation provided.
For more information, visit the Guide to Billing.
2012 rate of $0.0864/MW-day (with $0.0032 refund rate for Apr-Jun) 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.
Starting June 2008, monthly accrued actual costs related to AC2 are collected across all users of Schedule 9-1 through 9-5 based on usage shares with the costs allocated to the applicable schedules in accordance with the PJM tariff.
For more information, visit the Guide to Billing.
Apr-Jun 2012 rate of $0.0059/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.
2012 rate of $0.1692/MWh (with $0.0072 refund rate for Apr-Jun) 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.
2012 rate of $0.0025/FTR MWh (with $0.0001 refund rate for Apr-Jun) charged to FTR holders based on FTR MW and hours each FTR is in effect (regardless of congested hours and dollar value of FTR). 2012 rate of $0.0017/bid-hour (with $0.0001 refund rate for Apr-Jun) 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.
2012 rate of $0.0373/MWh (with $0.0016 refund rate for Apr-Jun) 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. 2012 rate of $0.0558 (with $0.0014 refund rate for Apr-Jun) 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.
2012 rate of $0.2271/Regulation MWh (with $0.0111 refund rate for Apr-Jun) charged to customers based on regulation obligation and regulation provided.
For more information, visit the Guide to Billing.
2012 rate of $0.0864/MW-day (with $0.0032 refund rate for Apr-Jun) 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.
Apr-Jun 2012 rate of $0.0059/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. This charge funds the administration of PJM Settlement, Inc. who acts as the contractual counterparty to PJM market transactions and performs the billing collection and credit management services for PJM members.
For more information, visit the Guide to Billing.
2012 rate of $0.00449/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. 2012 rate of $0.00397 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.
2012 rate of $0.0689/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’ real-time energy transactions. Note: The DEOK zone is exempt from Schedule-9 FERC charges until Oct 2012.
For more information, visit the Guide to Billing.
2012 rate of $0.00069/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’ real-time energy transactions.
For more information, visit the Guide to Billing.
2012 rate of $0.0108/MWh charged to transmission customers based on their energy delivered to load in the PJM Region, excluding load in the Dominion zone. 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.
2011 rate of $0.0132/MWh charged to transmission customers based on their energy delivered to load in the PJM Region, excluding load in the Dominion & ATSI 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 demand resources that can be converted fully into energy within ten minutes. For more information, visit the Guide to Billing.
PJM conducts day-ahead scheduling reserve markets to ensure the capability of generation and demand resources to meet reserve requirements on a forward basis. 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
Revenues are collected for generators requesting retirement where PJM studies find reliability issues that require the generation to continue operating. Cost allocations to zonal load and firm withdrawal rights are determined by PJM based on the beneficiaries. These responsible customers pay the generation owners a share of the Deactivation Avoidable Cost Rate or the FERC-approved Cost of Service Recovery Rate. Any time that the zonal cost allocations change, notice is provided to the Markets and Reliability Committee, Market Implementation Committee, and Market Settlements Working Group prior to the change being implemented.
For more information, visit the Guide to Billing.
All network and point-to-point load serving customers in the ComEd Zone pay ComEd (expected to end May 2014) and in the AEP Zone pay AEP (expected to end May 2020).
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.
Monthly charges to ComEd zonal network customers are calculated based on network service peak load contributions (as used for Network Service charges) at a 2012 rate of $64.12/MW/year. Monthly charges to AEP zonal network customers are calculated based on network service peak load contributions at a 2012 rate of $96.29/MW/year.
For more information, visit the Guide to Billing.
All network customers (except those in the Dominion, Duke 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 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.
For 2012, $4.96/MW-month of peak load is charged to all network customers serving load in the AEP, ComEd, and Dayton zones and $2.43/MW-month is charged in all other zones, except Dominion, Duke and ATSI.
For more information, visit the Guide to Billing.
Billing Adjustments - see BLI Adjustment Summary Report in MSRS for additional information on select adjustments.
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, 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. Low voltage charges also apply for the ATSI zone based on their peak load contribution in each ATSI utility service territory using the applicable customer’s low voltage billing factor for each ATSI service territory.
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 hours when the PJM transmission system is constrained are assessed to market participants based on the congestion price component of LMPs, and the revenues collected are allocated to FTR holders.
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 demand resources that can be converted fully into energy within ten minutes. For more information, visit the Guide to Billing.
PJM conducts day-ahead scheduling reserve markets to ensure the capability of generation and demand resources to meet reserve requirements on a forward basis. 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 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.
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 or nominated ILR that fail performance tests pay a penalty charge which is allocated to eligible LSEs. This billing is performed in the December billing cycle for June-December, then it is performed monthly for January-May.
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 hours when the PJM transmission system is constrained are assessed to market participants based on the congestion price component of LMPs, and the revenues collected are allocated to FTR holders.
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 hours when the PJM transmission system is constrained are assessed to market participants based on the congestion price component of LMPs, and the revenues collected are allocated to FTR holders.
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.
PJM conducts day-ahead scheduling reserve markets to ensure the capability of generation and demand resources to meet reserve requirements on a forward basis. 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 day-ahead scheduling reserve markets to ensure the capability of generation and demand resources to meet reserve requirements on a forward basis. For more information, visit the Guide to Billing.
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