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.

Charges: Daily demand charges calculated as network customers’ daily network service peak load contribution times 1/365th of the applicable zonal rate(s) for the zone(s) in which the network load is located. Monthly negative offset charges are rebated to AP zone network customers based on the applicable rates in PJM tariff Attachment H-11, section 4. Non-zone network service peak load contributions are coincident with the PJM Region peak. Daily low voltage charges are assessed to network customers in the ATSI zone for use of transmission facilities below 138 kV based on their network service peak load contribution MW times the low voltage rate times the percentage of their load serving those facilities.

Credits: PJM zonal network transmission service revenues allocated to the applicable zone’s transmission owners on a transmission revenue requirement basis. PJM non-zone network revenues allocated to transmission owners based on transmission revenue requirement ratio shares, with the ComEd, AEP, and Dominion shares further allocated to their respective zonal network customers based on demand charge ratios.

NITS Charge Summary

Low Voltage NITS Charge Summary

NITS Credit Summary

NITS Offset Charge Summary Non-Zone

NITS Credit Summary

Firm PTP Charges

Firm PTP Credit Summary

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.

Charges: Monthly demand charges for hourly, daily, weekly, and monthly delivery calculated based on the transmission customer’s reserved capacity (in MWh) times the discounted rate of $0.67/MWh. Rebates are provided for transaction MWh curtailed by PJM and for transmission congestion charges.

Credits: Total non-firm transmission service revenues allocated to PJM network and firm point-to-point transmission customers in proportion to their monthly demand charges.

Non-Firm PTP Charges

Non-Firm PTP Credit Summary

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.

Charges: All network customers serving load in a responsible zone pay for that zone’s applicable projects’ revenue requirements in proportion to their network service peak load share in that zone, and responsible merchant transmission owners also pay their share of applicable revenue requirements. Note that several EDCs bear these charges for the default suppliers in their territory.

Credits: Total revenues allocated to the applicable transmission enhancement project owners, or the applicable transmission zone network customers for zonal TOs that include these project costs in their network rates.

Transmission Enhancement Charge Summary

Transmission Enhancement Credit Summary

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.

Day-ahead Charges: Net day-ahead PJM Interchange is charged hourly at the PJM-wide day-ahead system energy price. Charges are positive for net buyers and negative for net sellers of day-ahead spot market energy.

Balancing Charges: Net real-time deviations from day-ahead PJM Interchange is charged hourly at the PJM-wide real-time system energy price. Charges may be positive or negative depending on the direction of the real-time deviation from dayahead interchange.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using the PJM-wide real-time system energy price on a two-month billing lag.

DA Daily Energy Transactions

RT Daily Energy Transactions for customer review and verification

Spot Market Energy Charge Summary

Energy & Inadvertent Load Recon Charge Summary

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.

Day-ahead Charges: A day-ahead Net Congestion Bill is calculated hourly as the sum of day-ahead withdrawal charges (i.e., all cleared day-ahead demand/decrement/load response bids and sale transactions priced at applicable buses’ day-ahead congestion prices) minus the sum of day-ahead injection credits (i.e., all cleared day-ahead generation/increment offers and purchase transactions priced at applicable buses’ day-ahead congestion prices). Hourly day-ahead implicit congestion charges equal the day-ahead Net Congestion Bill. Hourly explicit congestion charges for day-ahead energy transactions equal the scheduled MWh times the difference between day-ahead sink and source congestion prices and are assessed to the buyer (or point-to-point transmission customer, if applicable).

Balancing Charges: A balancing Net Congestion Bill is calculated hourly as the sum of balancing withdrawal charges (i.e., all deviations between demand/decrement/load response bids and sale transactions cleared day-ahead and real-time load, without losses, and sale transactions priced at the applicable buses’ real-time congestion prices) minus the sum of balancing injection credits (i.e., all deviations between generation/increment offers and purchase transactions cleared day-ahead and real-time generation and purchase transactions priced at the applicable buses’ real-time congestion prices). Hourly balancing implicit congestion charges equal the balancing Net Congestion Bill. Hourly explicit congestion charges for balancing energy transactions equal any real-time deviations from the transaction MWh cleared day-ahead times the difference between realtime sink and source congestion prices and assessed to the buyer (or point-to-point transmission customer, if applicable).

Credits: Total congestion revenues allocated as hourly credits based on FTR target allocations (FTR MW times the difference between day-ahead FTR sink and source congestion prices). Excess hourly congestion credits (including NYISO Unscheduled Transmission Service revenues, net MISO congestion adjustment, inadvertent interchange congestion contribution, and ARR and FTR Auction net revenues remaining after initial distribution to any ARR deficiencies) are used to proportionately eliminate target deficiencies in other hours of the month. Any additional excess monthly congestion revenues are allocated to previous deficient months of the planning period with any excess at the end of the planning period allocated proportionately to FTR holders with net positive FTR target allocations for that planning period. Any deficiencies remaining at the end of a planning period are eliminated by reallocating all planning period FTR congestion revenues among FTR holders to yield a uniform ratio of deficiency.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using the applicable source/sink congestion price on a two-month billing lag.

Transmission Congestion Charge Summary

Explicit Congestion Charges

Implicit Congestion and Loss Charge Details

FTR Target Credits

Monthly Congestion Credit Summary

Hourly Transmission Congestion Credits

Congestion and Loss Load Recon Charges

Congestion Uplift Charge Summary

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).

Day-ahead Charges: An hourly day-ahead Net Loss Bill is calculated as day-ahead withdrawal charges (i.e., all cleared dayahead demand/decrement/load response bids and sale transactions priced at applicable buses’ day-ahead loss prices) minus day-ahead injection credits (i.e., all cleared day-ahead generation/increment offers and purchase transactions priced at applicable buses’ day-ahead loss prices). Hourly day-ahead implicit loss charges equal the day-ahead Net Loss Bill. Hourly explicit loss charges for day-ahead energy transactions equal the scheduled MWh times the difference between day-ahead sink and source loss prices and assessed to the buyer (or point-to-point transmission customer, if applicable).

Balancing Charges: An hourly balancing Net Loss Bill is calculated as balancing withdrawal charges (i.e., all deviations between demand/decrement/load response bids and sale transactions cleared day-ahead and real-time load, without losses, and sale transactions priced at the applicable buses’ real-time loss prices) minus balancing injection credits (i.e., all deviations between generation/increment offers and purchase transactions cleared day-ahead and real-time generation and purchase transactions priced at the applicable buses’ real-time loss prices). Hourly balancing implicit loss charges equal the balancing Net Loss Bill. Hourly explicit loss charges for balancing energy transactions equal any real-time deviations from day-ahead transaction MWh times the difference between real-time sink and source loss prices and assessed to the buyer (or point-topoint transmission customer, if applicable).

Credits:Total hourly loss revenues, both day-ahead and balancing (including loss contribution of inadvertent interchange) allocated as hourly credits based on ratio shares of real-time load (without losses) plus exports that pay for transmission service (with non-firm exports receiving 31% of their allocation).

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using the applicable source/sink loss price on a two-month billing lag.

Reconciliation Credits: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using a $/MWh billing determinant calculated as the total loss credits divided by the total MWh of PJM real-time load plus exports (that pay for transmission service, with non-firm exports receiving 31% of their allocation) on a two-month billing lag.

Transmission Loss Charge Summary

Explicit Loss Charges Implicit Congestion and Loss Charge Details

Transmission Loss Credit Summary

Congestion and Loss Load Recon Charges

Transmission Loss Load Recon Credit Summary

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.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using the PJM-wide real-time system energy price on a two-month billing lag.

Inadvertent Interchange Charge Summary

Energy & Inadvertent Load Recon Charge Summary

Credits: 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).

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.

Load Response Summary

Econ Load Response Zonal Charge Allocations

Emergency Load Response Allocation Summary

Meter Correction Charge Summary

Meter Correction Allocation Charge Summary

Emergency Energy Charge and Credit Allocation Summary

Emergency Energy
Transactions

Charges: PJM’s monthly operating expenses for the following service categories are allocated to PJM members on an unbundled basis. Charge refunds are provided in the year following any year in which there is an over collection of PJM‘s monthly operating expenses.

Control Area Administration – 2012 rate of $0.1692/MWh (with $0.0047 refund rate for Jan-Mar) 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.

Financial Transmission Rights Administration – 2012 rate of $0.0025/FTR MWh (with $0.0001 refund rate for Jan-Mar) 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 Jan-Mar) 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).

Market Support – 2012 rate of $0.0373/MWh (with $0.0011 refund rate for Jan-Mar) 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 $0.0009 refund rate for Jan-Mar) is charged for each energy bid/offer segment price/quantity pair submitted, including those submitted during the rebidding period.

Regulation and Frequency Response Administration – 2012 rate of $0.2271/Regulation MWh (with $0.0075 refund rate for Jan-Mar) charged to customers based on regulation obligation and regulation provided.

Capacity Resource and Obligation Management – 2012 rate of $0.0864/MW-day (with $0.0022 refund rate for Jan-Mar) charged to LSEs based on their daily unforced capacity obligations and to capacity resource owners based on their daily unforced capacity (including FRRs).

Costs of Advanced Second Control Center (AC2) – 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.

Market Support Offset - Jan-Mar 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.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using a $/MWh billing determinant calculated as the Control Area Administration Service Rate plus the Market Support Service Rate for transmission customers on a two-month billing lag. Charge refund amounts are also reconciled using the applicable refund rate billing determinants. Schedule 9-6 AC2 charges are also reconciled using the applicable billing determinants.

Schedule 9 and 10 Charge Details

Advanced Second Control Center Charge Details

Schedule 9 & 10 Load Recon Charge Summary

Charges: Preliminary 2012 rate of $0.00500/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. Preliminary 2012 rate of $0.00442 is charged for each energy bid/offer segment price/quantity pair submitted, including those submitted during the rebidding period.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using the MMU rate on a two-month billing lag.

Schedule 9 and 10 Charge Details

Schedule 9 & 10 Load Recon Charge Summary

Charges: 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.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using the FERC rate on a two-month billing lag.

Schedule 9 and 10 Charge Details

Schedule 9 & 10 Load Recon Charge Summary

Charges: 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.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using the OPSI rate on a two-month billing lag.

Schedule 9 and 10 Charge Details

Schedule 9 & 10 Load Recon Charge Summary

Charges: 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.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using the NERC rate on a two-month billing lag.

Schedule 9 and 10 Charge Details

Schedule 9 & 10 Load Recon Charge Summary

Charges: 2012 rate of $0.0135/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 RFC’s actual costs are trued up in that year’s December billing cycle.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using the RFC rate on a two-month billing lag.

Schedule 9 and 10 Charge Details

Schedule 9 & 10 Load Recon Charge Summary

All Transmission Customers purchase this from PJM to schedule energy through, out, within, or into PJM.

Charges: Monthly charges for the operation of the PJM transmission owners’ control centers are calculated for transmission customers based on their monthly usage of the PJM transmission system. Point-to-Point Transmission Customers pay a poolwide rate of $0.1019/MWh based on their energy deliveries including losses, and network customers (and point-to-point customers serving load with point-to-point service) pay applicable zonal rates provided in Schedule 1A of the Tariff based on the real-time MWh of monthly load they serve.

Credits: The charges collected from network customers for each zone are provided to the applicable transmission owner, and the non-zone revenues (e.g., received from point-to-point customers) are allocated to PJM transmission owners based on fixed percentage shares provided in Schedule 1A of the Tariff.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using zonal $/MWh billing determinants equal to the applicable zonal Schedule 1A rates on a two-month billing lag.

Sched 1A Charge Summary

Sched 1A Credit Summary

Sched 1A Load Recon Charge Summary

All Transmission Customers purchase this from PJM to maintain acceptable transmission voltages.

Credits: Monthly credits provided to generation and transmission owners with FERC-approved reactive revenue requirements.

Charges: Monthly pool-wide reactive revenue requirements allocated as charges to point-to-point customers (and to network customers in transmission zones with no reactive revenue requirements) based on their monthly peak usage of the PJM transmission system. Monthly peak usage equals the total hourly amounts of transmission capacity reserved, and not curtailed by PJM, divided by 24. The remaining reactive revenue requirements for each transmission zone not recovered from point-topoint customers are allocated to the network customers serving load in that zone based on their monthly network service peak load contributions.

PJM conducts a regulation market to continuously balance generation resources with PJM load and to maintain Interconnection frequency within acceptable limits.

Credits: Generators and demand resources receive hourly credits for pool- and self-scheduled regulation priced at the regulation market clearing price. Additional credits provided to pool-scheduled regulating resources for any unrecovered portion of regulation offer plus opportunity cost.

Charges: PJM LSEs have an hourly regulation obligation equal to their real-time load (without losses) ratio share of PJM assignments (adjusted for any bilateral regulation transactions). Hourly charges calculated by allocating total credits across all positive adjusted obligations. Additional charges are assessed for any unrecovered cost payments that PJM provides to regulation suppliers and allocated to regulation market purchasers based on their share of any portion of their adjusted obligation in excess of their self-scheduled regulation.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are
reconciled on an hourly basis using a $/MWh billing determinant calculated as the total regulation market charges divided by
the total MWh of PJM real-time load served on a two-month billing lag.

Regulation Summary

Regulation Credits

Load Response Regulation Credits

Reg Load Recon Charge Summary

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.

Credits: Generators that increase output and demand resources that decrease consumption in response to a synchronized reserve event receive Tier 1 credits equal to response MWh times synchronized reserve energy premium less its hourly LMP. Resources receive Tier 2 hourly credits for pool- and self-scheduled synchronized reserve priced at the applicable reserve zone’s Tier 2 clearing price. Additional credits provided to pool-scheduled synchronized reserve resources for any portion of synchronized reserve offer plus opportunity cost, energy use cost, and start-up cost not recovered via Synchronized Reserve Market Clearing Price revenues.

Charges: PJM LSEs have an hourly synchronized reserve obligation equal to their real-time load (without losses) ratio share of their reserve market’s total assignments (adjusted for any bilateral synchronized reserve transactions). Tier 1 charges for each participant equal their ratio share of the total Tier 1 credits based on the amount of Tier 1 synchronized reserve applied to their obligation. Tier 2 hourly charges for each participant equal their reserve market’s hourly Tier 2 clearing price times the MWh of Tier 2 synchronized reserve self-scheduled that hour toward their obligation plus that which was purchased from that synchronized reserve market, plus their share of any unrecovered costs incurred by assigned Tier 2 resources above the Tier 2 clearing price, plus their share of costs of those Tier 2 resources assigned in addition to that which was estimated prior to a given hour.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using the applicable reserve zone’s $/MWh billing determinant calculated as the total applicable reserve zone charges divided by the total MWh of PJM real-time load served in the that market on a two-month billing lag.

Synchronized Reserve Credit Summary

Synchronized Reserve Tier 1 Credits

Synchronized Reserve Tier 2 Credits

Synchronized Reserve Obligation Details

Synchronized Reserve Tier 1 Charge Summary

Synchronized Reserve Tier 2 Charge Summary

Load Response Tier 1 Credits

Load Response Tier 2 Credits

Synchronized Reserve Load Recon Charge Summary

PJM conducts day-ahead scheduling reserve markets to ensure the capability of generation and demand resources to meet reserve requirements on a forward basis.

Credits: Daily credits provided to eligible generator and demand response resources cleared day-ahead based on their cleared MWh of day-ahead scheduling reserve times the day-ahead scheduling reserve clearing price.

Charges: PJM LSEs have an hourly day-ahead scheduling reserve obligation equal to their real-time load (without losses) ratio share of the market’s total assignments (adjusted for any bilateral day-ahead scheduling reserve transactions). Total hourly cost of day-ahead scheduling reserve is allocated based on obligation ratio shares.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using the $/MWh billing determinant calculated as the total charges divided by the total MWh of PJM real-time load on a two-month billing lag.

Day-ahead cheduling
Reserve Summary

Day-ahead Scheduling Reserve Credits

Day-ahead Scheduling Reserve Load Recon Charge Summary

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.

Day-ahead Credits: Daily credits provided to pool-scheduled generators, demand response, and transactions cleared dayahead for any portion of their offer amount in excess of their scheduled MWh times day-ahead bus LMP.

Balancing Credits: Daily credits for specified operating period segments provided to eligible pool-scheduled generators, demand response, and import transactions in real-time for any portion of their offer amount in excess of: (1) scheduled MWh times day-ahead bus LMP; (2) MWh deviation from day-ahead schedule times real-time bus LMP; (3) any day-ahead operating reserve credits; (4) any day-ahead scheduling reserve market revenues in excess of offer; (5) any synchronized reserve market revenues in excess of offer plus opportunity, energy use, and startup costs; and (6) any applicable reactive services credits. Cancellation credits are based on actual costs submitted to PJM Market Settlements. Credits for lost opportunity costs are also provided to generators reduced or suspended by PJM for reliability purposes.

Day-ahead Charges: Total daily cost of operating reserve in the day-ahead market is allocated based on day-ahead load (including cleared demand, demand response, and decrement bids) plus exports ratio shares.

Balancing Charges: Total daily cost of operating reserve in the balancing market related to resources identified as Credits for Deviations is allocated based on regional shares of real-time locational deviations from the following day-ahead scheduled quantities of: (1) cleared generation offers (only for generating units not following PJM dispatch instructions and not assessed deviations based on their real-time desired MWh); (2) cleared increment offers and purchase transactions; and (3) cleared demand bids, decrement bids, and sale transactions. Total daily cost of operating reserve in the balancing market related to resources identified as Credits for Reliability is allocated based on regional shares of real-time load (without losses) plus exports.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an daily basis using a $/MWh billing determinant calculated as the total charges allocated to real-time load plus exports divided by the total MWh of PJM real-time load plus exports on a two-month billing lag.

Operating Reserve Charge Summary

Operating Reserve Generator Credit Details

Operating Reserve Lost Opportunity Cost Credits

Operating Reserve Transaction Credits

Operating Reserve Generator Deviations

Operating Reserve Deviation Summary

Operating Reserve Transaction Credits

Operating Reserve for Load Response Credit Details

Operating Reserve for Load Response Deviation Charge Summary

Operating Reserve for Load Response Charge Allocations

Regional Balancing Operating Reserve Charge Summary

Balancing Operating Reserve Load Recon Charge Summary

Credits: 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.

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.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using a $/MWh billing determinant calculated as the total charges divided by the total MWh of PJM real-time load plus exports on a two-month billing lag.

Synchronous Condensing Credits

Synchronous Condensing Charge Summary

Synchronous Condensing Load Recon Charge Summary

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.

Credits: Daily credits are calculated for each eligible generator in real-time and equal the operating reserve credits for generation increased, or equal the lost opportunity costs for generation reduced or instructed to condense, to provide reactive services.

Charges: Total daily cost of reactive services is allocated separately for each PJM transmission zone based on real-time load (without losses) ratio shares in the applicable transmission zone.

Reconciliation Charges: Retail load schedules with reconciliation data (in kWh) provided by the applicable EDC are reconciled on an hourly basis using the applicable zone’s $/MWh billing determinant calculated as the total applicable zone’s charges divided by the total MWh of real-time load served in the that zone on a two-month billing lag.

Reactive Services Credits

Synchronous Condensing Credits

Reactive Services Charge Summary

Reactive Svcs Load Recon Charge Summary

All Transmission Customers purchase this from PJM to ensure the reliable restoration following a shut down of the PJM transmission system.

Credits: Monthly credits provided to generators with approved black start revenue requirements.

Charges: Monthly pool-wide black start revenue requirements allocated as charges to point-to-point customers based on their monthly peak usage of the PJM transmission system. Monthly peak usage equals the total hourly amounts of transmission capacity reserved, and not curtailed by PJM, divided by 24. The remaining black start revenue requirements nominated by each zonal Transmission Owner not recovered from point-to-point customers are allocated to the network customers serving
load in that transmission zone based on their monthly network service peak load contributions.

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.

Charges: Monthly auction charges are calculated for each market participant for each FTR (in 0.1 MW increments) purchased in the annual or monthly auctions based on the FTR’s market price.

Credits: Monthly auction credits are calculated for each market participant for each FTR (in 0.1 MW increments) sold in the annual or monthly auctions based on the FTR’s market price.

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.

Credits: Annual FTR auction net revenues are allocated as daily credits based on ARR target allocations, which equal the
ARR MW (divided by the number of auction rounds) times the difference between auction clearing prices at the ARR sink and
source. Any ARR target deficiencies may be proportionately eliminated by any monthly FTR auction net revenues and excess
congestion revenues in that planning period.

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-specified transactions for cleared capacity.

Charges: Each buy bid MW cleared in an  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 the MW shares of cleared buy bids adjusted by cleared buy bid transactions for the incremental auction.  Resource make-whole payments for the base residual auction 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.

RPM Auction Charges and
Credits

RPM Auction Make Whole Charge Summary

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.

Credits: CTRs equal to the unforced capacity imported into the LDA (less any incremental CTRs) are allocated to LSEs in that LDA based on daily unforced capacity obligations. These MW allocations are priced at the difference between the LDA’s clearing price and the unconstrained price.

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.

Credits: Incremental CTR MW are priced at the sum of: 1) locational price adder of the sink LDA minus that of the Source LDA from the Base Residual Auction; and 2) locational price adder of the sink LDA minus that of the source LDA from the Second Incremental Auction multiplied by the increase in unforced capacity imported into the sink LDA in the Second Incremental Auction compared to the Base Residual Auction, divided by the base unforced capacity imported into the sink LDA.

Bilateral capacity transactions for multi-day durations are settled in the PJM capacity markets.

Charges: Sellers are charged for the transaction MW times the transaction’s pricing point for each day for which the transaction is in effect.

Credits: Buyers are credited for the transaction MW times the transaction’s pricing point for each day for which the transaction is in effect.

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.

Charges: For each non-compliant reduction event, under-compliance MW (on an unforced capacity basis) are charged at the lesser of one divided by the actual number of events during the year or 0.50 of the Weighted Annual Revenue Rate.   The Weighted Annual Revenue Rate equals the average rate for all cleared Demand Resources and certified ILR, weighted by the MWs cleared or certified at each price, multiplied by the number of days in the Delivery Year.  The total Compliance Penalty Charge for the Delivery Year is capped at the annual revenue received for such resources.

Credits: Revenues from events in a given month are allocated to Demand Resource and ILR Providers that reduced in excess of their commitment. Any resource credit by event is capped at their excess MW times 1/5th of their Annual Revenue Rate. Revenues above that cap are allocated to LSEs based on their average daily unforced capacity obligations during the month of the event.

DR & ILR Compliance Penalty Ch and Cr

DR & ILR Compliance Penalty Residual Credit Summary

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.

Charges: Each capacity resource’s deficiency MW for each day it is deficient pays the daily deficiency rate.

Credits: Total revenues each day are allocated to LSEs that paid a Locational Reliability charge that day based on their daily unforced capacity obligations.

Non-Compliance Charge Summary

Deficiency Credit Summary

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.

Charges:Each capacity resource’s installed capacity minus its highest rating in the relevant testing period (on an unforced capacity basis) pays a daily deficiency rate which is the  weighted average capacity resource clearing price plus the higher of:  1) 0.2 times the weighted average capacity resource clearing price or 2) $20/MW-day;

Credits: Total revenues each day are allocated to LSEs that paid a Locational Reliability charge that day based on their daily unforced capacity obligations.

Non-Compliance Charge Summary

Deficiency Credit Summary

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.

Charges: Capacity market sellers with import capability cleared in a base residual auction based on a qualifying transmission upgrade are charged each day that the upgrade is not in service during the applicable delivery year and the seller does not obtain replacement capacity resources.  The import capability MW are charged at the higher of the following rates:  1) two times the locational price adder of the applicable LDA; or 2) the Net CONE less the clearing price in the applicable LDA.

Credits: Total revenues each day are allocated to LSEs that paid a Locational Reliability charge that day based on their daily unforced capacity obligations.

Non-Compliance Charge Summary

Deficiency Credit Summary

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.

Charges: Each generation capacity resource’s cleared MW for each day of the peak season that is out-of-service on a maintenance outage not authorized by PJM pays the daily deficiency rate times (1-EFORd).

Credits: Total revenues each day are allocated to LSEs that paid a Locational Reliability charge that day based on their daily unforced capacity obligations.

Non-Compliance Charge Summary

Deficiency Credit Summary

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.

Charges: Net peak period capacity shortfall MW are charged at the weighted average resource clearing price for the applicable LDA (except for FRR capacity that are charged at the LDA’s Net CONE).

Credits: Total revenues for the delivery year for each LDA are allocated to resources with peak period excesses based on their excess MW. Since these allocations are capped, any remaining credits are allocated to LSEs that paid a Locational Reliability charge based on their daily unforced capacity obligations.

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.

Charges: Net capability testing shortfall MW are charged daily at the weighted annual revenue rate for the applicable zone plus the greater of 0.2 times that weighted annual revenue rate or $20/MW-day).

Credits: Total revenues each day are allocated to LSEs that paid a Locational Reliability charge that day based on their daily unforced capacity obligations.

Load Management Test Failure Charge Summary

Deficiency Credit Summary

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).

Charges: 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.

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.

Charges: 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.

Credits: Total revenues are allocated to ComEd, AEP, and Dayton in accordance with Schedule 13.

Expansion Cost Recovery Charge Summary

Expansion Cost Recovery Credit Summary

Charges: Hourly charges to NYISO for any costs incurred due to unscheduled use of the PJM transmission system in accordance with the PJM-NYPP Interconnection Agreement Schedule 6.02.

Credits: Total hourly charges are allocated as credits with monthly excess congestion credits.

Charges: Charges are allocated to PJM Mid-Atlantic transmission owners based on transmission revenue requirement shares.

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.

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.

Charges: Charges are being collected for a unit in the PSEG zone based on a Cost of Service Recovery Rate which is expected to end after August 2012. From September 2010 through August 2012, monthly charges are allocated on a one-month lag in accordance with the following study results: http://www.pjm.com/planning/generation-retirements/~/media/planning/gen-retire/2011-and-2012-zonal-cost-allocation-for-retaining-husdon-unit-1-generator.ashx. Since Hudson Transmission Partners’ facility is not yet in service, their charges must be deferred resulting in the following normalized cost allocations: AE (0.61494%), ComEd (2.15787%), JCPL (8.95572%), Neptune (4.08095%), PenElec (2.23614%), ECP (3.17531%), PSEG (75.78265%), and RECO (2.99642%). Note that the zonal charges are further allocated based on network service peak load contributions within the applicable zone. Charge refunds are also being provided from September 2008 through February 2017 for a plant in the PSEG zone that was previously collecting payments but has since decided to stay operational. These refunds are being allocated to network customers in the PSEG (41.8707%), PECO (19.1279%), JCPL (25.2497%), Delmarva (6.1420%), AE (6.2832%), and RECO (1.3265%) zones based on the network service peak load contributions within the applicable zones.

Charges are being collected for units in the PECO zone based on a Cost of Service Recovery Rate which is expected to end after December 2011 for Cromby and after May 2012 for Eddystone. Monthly charges are allocated on a one-month lag in accordance with the following study results: http://pjm.com/planning/generation-retirements/~/media/planning/gen-retire/cromby-2-zonal-cost-allocation-for-2011.ashx and http://pjm.com/planning/generation-retirements/~/media/planning/gen-retire/eddystone-2-zonal-cost-allocation-for-2011.ashx. Since Hudson Transmission Partners’ facility is not yet in service, their charges must be deferred resulting in the following normalized cost allocations: for Cromby - AE (0.29006%), JCPL (1.16023%), Neptune (0.13003%), PECO (96.70934%), ECP (0.03001%), PSEG (1.62032%), and RECO (0.06001%); for Eddystone - JCPL (3.7609%), Neptune (0.4012%), PECO (84.4148%), ECP (0.2908%), PSEG (10.701%), and RECO (0.4313%). Note that the zonal charges are further allocated based on network service peak load contributions within the applicable zone.

Generation Deactivation Charge Summary

Generation Deactivation Refund Charge Summary