Congestion and Marginal Losses

Transcription

1 Section 10 Congestion and Marginal Losses Congestion and Marginal Losses The Locational Marginal Price (LMP) is the incremental price of energy at a bus. The LMP at any bus is made up of three components: the system marginal price (SMP), the marginal loss component of LMP (MLMP), and the congestion component of LMP (CLMP). SMP, MLMP and CLMP are a product of the least cost, security constrained dispatch of system resources to meet system load. SMP is the incremental cost of energy, given the current dispatch, ignoring losses and congestion. Losses refer to energy lost to physical resistance in the transmission and distribution network as power is moved from generation to load. Marginal losses are the incremental change in system power losses caused by changes in the system load and generation patterns. Congestion occurs when available, least-cost energy cannot be delivered to all loads for a period because transmission facilities are not adequate to deliver that energy. When the least-cost available energy cannot be delivered to load in a transmissionconstrained area, higher cost units in the constrained area must be dispatched to meet that load. 1 The result is that the price of energy in the constrained area is higher than in the unconstrained area because of the combination of transmission limitations and the cost of local generation. Congestion is neither good nor bad but is a direct measure of the extent to which there are differences in the cost of generation that cannot be equalized because of transmission constraints. The components of LMP are the basis for determining participant and location specific congestion and marginal losses. The Market Monitoring Unit (MMU) analyzed marginal losses and congestion in PJM markets for Overview Marginal Loss Cost Before June 1, 2007, the PJM economic dispatch and LMP models did not include marginal losses. The losses were treated as a static component of load, and the physical nature and location of power system losses were ignored. The PJM Tariff required implementation of marginal loss modeling when required technical systems became available. On June 1, 2007, PJM began including marginal losses in economic dispatch and LMP models. 2 The primary benefit of a marginal loss calculation is that it more accurately models the physical reality of power system losses, which permits increased efficiency and more optimal asset utilization. Marginal loss modeling creates a separate marginal loss price for every location on the power grid. This marginal loss price (MLMP) is a component of LMP that is charged to load and credited to generation. network losses are determined by using a linearized approximation model based on the loss sensitivities to location-specific changes in power injection and withdrawal. Average losses are then calculated from total losses. marginal loss costs equal net marginal loss costs plus explicit marginal loss costs plus net inadvertent loss costs. Net marginal loss costs equal load loss payments minus generation loss credits. Explicit marginal loss costs are the net marginal loss costs associated with point-to-point energy transactions. Net inadvertent loss costs are the losses associated with hourly difference between the net actual energy flow and the net scheduled energy flow into or out of the PJM control area in that hour. 3 Unlike the other categories of marginal loss accounting, inadvertent loss costs are common costs not directly attributable to specific participants. Inadvertent related loss costs are distributed to load on a load ratio basis. Each of these categories of marginal loss costs is comprised of day-ahead and balancing marginal loss costs. Day-ahead marginal loss costs are based on day-ahead MWh priced at the marginal loss price component of Locational Marginal Price (LMP) while balancing marginal loss costs are based on deviations between day-ahead and real-time MWh priced at the marginal loss price component of Locational Marginal Price (LMP) in the Real-Time Energy Market. 1 This is referred to as dispatching units out of economic merit order. Economic merit order is the order of all generator offers from lowest to highest cost. Congestion occurs when loadings on transmission facilities mean the next unit in merit order cannot be used and a higher cost unit must be used in its place. 2 For additional information, see OATT Section OA. Schedule 1 (PJM Interchange Energy Market) State of the Market Report for PJM 261

2 2011 State of the Market Report for PJM Marginal loss charges can be positive or negative with respect to the reference bus. If an increase in load at a bus would decrease losses, the marginal loss component of LMP of that bus will be negative. If an increase in generation at a bus would result in an increase in losses, the marginal loss component of that bus will be negative. If an increase of load at a bus would increase losses, the marginal loss component of LMP at that bus will be positive. If an increase in generation at a bus results in a decrease of system losses, then the marginal loss component of LMP at that bus will be positive. Day-ahead marginal loss charges and credits are based on MWh and LMP in the Day-Ahead Energy Market. Balancing marginal loss charges and credits are based on the load or generation deviations between the Day- Ahead and Real-Time Energy Markets and LMP in the Real-Time Energy Market. If a participant has realtime generation or load that is greater than its dayahead generation or load then the deviation will be positive. If there is a positive load deviation at a bus where the real-time LMP has a positive marginal loss component, positive balancing marginal loss costs will result. Similarly, if there is a positive load deviation at a bus where real-time LMP has a negative marginal loss component, negative balancing marginal loss costs will result. If a participant has real-time generation or load that is less than its day-ahead generation or load then the deviation will be negative. If there is a negative load deviation at a bus where real-time LMP has a positive marginal loss component, negative balancing marginal loss costs will result. Similarly, if there is a negative load deviation at a bus where real-time LMP has a positive marginal loss component, negative balancing marginal loss costs will result. Marginal loss credits or loss surplus is the remaining loss amount from overcollection of marginal losses, after accounting for net energy charges and residual market adjustments, that is paid back in full to load and exports on a load ratio basis. Marginal loss credits are calculated as the day-ahead and balancing transmission loss charges paid by all customer accounts each hour, plus the spot market energy value of the actual transmission loss MWh during that hour, plus residual net market adjustments in that hour. 4 Residual net market 4 See PJM. Manual 28: Operating Agreement Accounting, Revision 39 (January 1, 2008). Note that the over collection is not calculated by subtracting the prior calculation of average losses from the calculated total marginal losses. adjustments are common costs, not directly attributable to specific participants, that are deducted from total marginal loss credits before marginal loss credits are distributed on a load weighted ratio basis. Residual market adjustments consist of the Known Day-Ahead Error Value (KDAEV), day-ahead loss MW congestion value and balancing loss MW congestion value. KDAEV are costs associated with MW imbalances created by discontinuities in, and adjustments to, the day-ahead market solution. The day-ahead and balancing loss congestion values are congestion costs associated with loss related MW. Marginal Loss Costs. marginal loss charges decreased by $255.3 million or 15.6 percent, from $1,634.8 million in 2010 to $1,379.5 million in Day-ahead marginal loss costs decreased by $235.1 million or 14.1 percent, from $1,665.6 million in 2010 to $1,430.5 million in Balancing marginal loss costs decreased by $20.3 million or 65.9 percent from -$30.7 million in 2010 to -$51.0 million in On June 1, 2011, PJM integrated the American Transmission Systems, Inc. (ATSI) Control Zone. The metrics reported in this section treat ATSI as part of MISO for the period from January through May and as part of PJM for the period from June through December. Monthly Marginal Loss Costs. Fluctuations in monthly marginal loss costs continued to be substantial. In 2011, these differences were driven by varying load and energy import levels, different patterns of generation and weather-induced changes in demand. Monthly marginal loss costs in 2011 ranged from $70.6 million in December to $213.7 million in July. Marginal Loss Credits. Marginal Loss Credits are calculated as total net energy charges (total energy charges minus total energy credits) plus total net marginal loss charges (total marginal loss charges minus total marginal loss credits plus inadvertent and residual net market adjustments). Marginal loss credit or loss surplus is the remaining loss amount from overcollection of marginal losses, after accounting for net energy charges and residual market adjustments that is paid back in full to load and exports on a load ratio basis. The marginal loss 262 Section 10 Congestion and Marginal Losses

3 Section 10 Congestion and Marginal Losses credits decreased by $250 million or 29.9 percent, from $836.7 million in 2010 to $586.7 million in Zonal marginal loss costs. In 2011, zonal marginal loss costs ranged from $3.2 million in RECO to $318.6 million in AEP. Compared to 2010, 2011 had a decrease in marginal loss costs across the PJM control zones, except PECO and DAY control zones. marginal loss costs in PJM in 2011 also changed due to the addition of the ATSI Control Zone, which accounted for $19.3 million or 1.4 percent of the total marginal loss costs. 5 Congestion Cost congestion costs equal net congestion costs plus explicit congestion costs plus net inadvertent congestion costs. Net congestion costs equal load congestion payments minus generation congestion credits. Explicit congestion costs are the net congestion costs associated with point-to-point energy transactions. Net inadvertent congestion costs are the congestion costs associated with hourly difference between the net actual energy flow and the net scheduled energy flow into or out of the PJM control area in that hour. Unlike the other categories of congestion cost accounting, inadvertent congestion costs are common costs not directly attributable to specific participants. Inadvertent related congestion costs are distributed to load on a load ratio basis. Each of these categories of congestion costs is comprised of day-ahead and balancing congestion costs. Day-ahead congestion costs are based on day-ahead MWh while balancing congestion costs are based on deviations between day-ahead and real-time MWh priced at the congestion price in the Real-Time Energy Market. Congestion charges can be both positive and negative. When a constraint binds, the price effects of that constraint vary. The system marginal price (SMP) is uniform for all areas, while the congestion components of Locational Marginal Price (LMP) will either be positive or negative in a specific area, meaning that actual LMPs are above or below the SMP. 6 If an area is downstream from the constrained element, the area will experience positive congestion costs. If an area is upstream from the 5 See the 2011 State of the Market Report for PJM, Volume II, Appendix G, Congestion and Marginal Losses, at Zonal Marginal Loss Costs. 6 The SMP is the price of the distributed load reference bus. The price at the reference bus is equivalent to the five minute real-time or hourly day-ahead load weighted PJM LMP. constrained element, the area will experience negative congestion costs. Day-ahead congestion charges and credits are based on MWh and LMP in the Day-Ahead Energy Market. Balancing congestion charges and credits are based on load or generation deviations between the Day-Ahead and Real-Time Energy Markets and LMP in the Real- Time Energy Market. If a participant has real-time generation or load that is greater than its day-ahead generation or load then the deviation will be positive. If there is a positive load deviation at a bus where realtime LMP has a positive congestion component, positive balancing congestion costs will result. Similarly, if there is a positive load deviation at a bus where real-time LMP has a negative congestion component, negative balancing congestion costs will result. If a participant has real-time generation or load that is less than its day-ahead generation or load then the deviation will be negative. If there is a negative load deviation at a bus where real-time LMP has a positive congestion component, negative balancing congestion costs will result. Similarly, if there is a negative load deviation at a bus where real-time LMP has a positive congestion component, negative balancing congestion costs will result. Congestion. congestion costs decreased by $425.4 million or 29.9 percent, from $1,423.6 million in 2010 to $998.2 million in Dayahead congestion costs decreased by $468.2 million or 27.3 percent, from $1,713.1 million in 2010 to $1,244.9 million in Balancing congestion costs increased by $42.8 million or 14.8 percent from -$289.5 million in 2010 to -$246.7 million in On June 1, 2011, PJM integrated the American Transmission Systems, Inc. (ATSI) Control Zone. The metrics reported in this section treat ATSI as part of MISO for the period from January through May and as part of PJM for the period from June through December. Monthly Congestion. Fluctuations in monthly congestion costs continued to be substantial. In 2011, these differences were driven by varying load and energy import levels, different patterns 7 The total zonal congestion numbers were calculated as of March 2, 2012 and are, based on continued PJM billing updates, subject to change State of the Market Report for PJM 263

4 2011 State of the Market Report for PJM of generation, weather-induced changes in demand and variations in congestion frequency on constraints affecting large portions of PJM load. Monthly congestion costs in 2011 ranged from $35.0 million in May to $241.6 million in January. Congestion of Locational Marginal Price (LMP). To provide an indication of the geographic dispersion of congestion costs, the congestion component of LMP (CLMP) was calculated for control zones in PJM. Price separation among eastern, southern and western control zones in PJM was primarily a result of congestion on the AP South interface, the 5004/5005 interface, the Belmont transformer, West Interface, and the AEP- Dominion interface. (Table 10 27) Congested Facilities. Congestion frequency continued to be significantly higher in the Day- Ahead Market than in the Real-Time Market in Day-ahead congestion frequency increased by 45.8 percent from 106,253 congestion event hours in 2010 to 154,868 congestion event hours in Day-ahead, congestion-event hours decreased on internal PJM interfaces while congestion-event hours increased on transmission lines, transformers and reciprocally coordinated flowgates between PJM and the MISO. Real-time congestion frequency decreased by 0.4 percent from 23,422 congestion event hours in 2010 to 22,468 congestion event hours in Real-time, congestion-event hours decreased on the internal PJM interfaces and transmission lines, while congestion-event hours increased on transformers and reciprocally coordinated flowgates between PJM and MISO. Facilities were constrained in the Day-Ahead Market more frequently than in the Real-Time Market. The Day-Ahead market is consequently more-frequent constrained conditions compared to its corresponding Real-Time Market. During 2011, for only 5.6 percent of Day-Ahead Market facility constrained hours were the same facilities also constrained in the Real-Time Market. During 2011, for 38.0 percent of Real-Time Market facility 8 In order to have a consistent metric for real-time and day-ahead congestion frequency, real-time congestion frequency is measured using the convention that an hour is constrained if any of its component five-minute intervals is constrained. constrained hours, the same facilities were also constrained in the Day-Ahead Market. The AP South Interface was the largest contributor to congestion costs in With $238.9 million in total congestion costs, it accounted for 23.9 percent of the total PJM congestion costs in The top five constraints in terms of congestion costs together contributed $466.2 million, or 46.7 percent, of the total PJM congestion costs in The top five constraints were the AP South interface, the 5004/5005 interface, West interface, the Belmont transformer and the AEP Dominion interface. Zonal Congestion.9 Measured in terms of the total congestion bill, calculated by subtracting generation congestion credits from load congestion payments plus explicit congestion costs by zone, ComEd was the most congested zone in ComEd had -$1,007.3 million in total load charges, -$1,277.3 million in total generation credits and -$30.9 million in explicit congestion, providing $239.0 million in total net congestion charges, reflecting significant local congestion between local generation and load, despite being on the upstream side of system wide congestion patterns. The Electric Junction Nelson transmission line, Crete St. Johns flowgate (a reciprocally coordinated flowgate between PJM and MISO), AP South interface, East Frankfort Crete transmission line and the Bunsonville Eugene flowgate contributed $104.7 million, or 43.8 percent of the total ComEd Control Zone congestion costs. Similarly, the AEP Control Zone recorded the second highest congestion cost in PJM in 2011, with $195.1 million. The AP South interface contributed $33.1 million, or 17.0 percent of the total AEP Control Zone congestion cost in The AP Control Zone recorded the third highest congestion cost in PJM in 2011, with a cost of $143.9 million. The AP South interface contributed $63.9 million, or 44.4 percent of the total AP Control Zone congestion cost in The control zones in the Western (AEP, AP, ATSI, ComEd, DAY and DLCO) and Southern (Dominion) regions accounted for $737.2 million, 9 Tables reporting zonal congestion have been moved from this section of the report to Appendix G. See the 2011 State of the Market Report for PJM, Volume II, Appendix G, Congestion and Marginal Losses. 10 The total zonal congestion numbers were calculated as of March 2, 2012 and are, based on continued PJM billing updates, subject to change. As of March 2, 2012, the total zonal congestion related numbers presented here differed from the March 2, 2012 PJM totals by $0.72 Million, a discrepancy of 0.07 percent (.0007). 264 Section 10 Congestion and Marginal Losses

5 Section 10 Congestion and Marginal Losses or 73.9 percent of congestion cost and the control zones in the Eastern region accounted for $261.0 million or 26.1 percent of congestion cost. Ownership. In 2011, financial companies as a group were net recipients of congestion credits, and physical companies were net payers of congestion charges. In 2011, financial companies received $108.2 million in net congestion credits, a decrease of $60.3 million or 35.8 percent compared to In 2011, physical companies paid $1,107.2 million in net congestion charges, a decrease of $484.9 million or 30.4 percent compared to Conclusion Marginal losses are incremental change in real system power losses caused by changes in system load and generation patterns. marginal loss costs decreased by $255.3 million or 15.6 percent, from $1,634.8 million in 2010 to $1,379.5 million in Marginal loss costs were significantly higher in the Day-Ahead Market than the Real-Time Market. The net marginal loss bill is calculated by subtracting the generation loss credits from the sum of load loss charges, net explicit loss charges and net inadvertent loss charges. Since the net marginal bill is calculated on the basis of marginal, rather than average losses, there is an overcollection of marginal loss related costs. This overcollection, net of total energy charges and residual market adjustments 11, is the source of marginal loss credits. Marginal loss credits are fully distributed back to load and exports. Marginal loss credits were $586.7 million in Congestion reflects the underlying characteristics of the power system, including the nature and capability of transmission facilities, the cost and geographical distribution of generation facilities and the geographical distribution of load. congestion costs decreased by $425.4 million or 29.9 percent, from $1,423.6 million in 2010 to $998.2 million in Congestion costs were significantly higher in the Day-Ahead Market than in the Real-Time Market. Congestion frequency was also significantly higher in the Day-Ahead Market than in the Real-Time Market. ARRs and FTRs served as an effective, but not total, offset against congestion. ARR and FTR revenues offset 96.8 percent of the total congestion costs in the Day-Ahead Energy Market and the balancing energy market within PJM for the 2010 to 2011 planning period. 12 During the first seven months of the 2011 to 2012 planning period, total ARR and FTR revenues offset more than 100 percent of the congestion costs within PJM. FTRs were paid at 88.1 percent of the target allocation level for the 12-month period of the 2010 to 2011 planning period, and at 84.9 percent of the target allocation level for the first seven months of the 2011 to 2012 planning period. 13 Revenue adequacy, measured relative to target allocations for a planning period is not final until the end of the period. The congestion metric requires careful review when considering the significance of congestion. The net congestion bill is calculated by subtracting generating congestion credits from load congestion payments. The logic is that increased congestion payments by load are offset by increased congestion revenues to generation, for the area analyzed. Net congestion, which includes both load congestion payments and generation congestion credits, is not a good measure of the congestion costs paid by load from the perspective of the wholesale market. 14 While total congestion costs represent the overall charge or credit to a zone, the components of congestion costs measure the extent to which load or generation bear total congestion costs. congestion payments, when positive, measure the total congestion cost to load in an area. congestion payments, when negative, measure the total congestion credit to load in an area. Negative load congestion payments result when load is on the lower priced side of a constraint or constraints. For example, congestion across the AP South interface means lower prices in western control zones and higher prices in eastern and southern control zones. in western control zones will benefit from lower prices and receive a congestion credit (negative 11 Residual net market adjustments are common costs, not directly attributable to specific participants, that are deducted from total marginal loss credits before marginal loss credits are distributed on a load weighted ratio basis. Residual market adjustments consist of the Known Day-Ahead Error Value (KDAEV), day-ahead loss MW congestion value and balancing loss MW congestion value. KDAEV are costs associated with MW imbalances created by discontinuities in, and adjustments to, the day-ahead market solution. The day-ahead and balancing loss congestion values are congestion costs associated with loss related MWs. 12 See the 2011 State of the Market Report for PJM Section 12, Financial Transmission and Auction Revenue Rights, at Table 12-36, ARR and FTR congestion hedging: Planning periods 2010 to 2011 and 2011 to See the 2011 State of the Market Report for PJM Section 12, Financial Transmission and Auction Revenue Rights, at Table 12-22, Monthly FTR accounting summary (Dollars (Millions)): Planning periods 2010 to 2011 and 2011 to The actual congestion payments by retail customers are a function of retail ratemaking policies and may or may not reflect an offset for congestion credits State of the Market Report for PJM 265

6 2011 State of the Market Report for PJM load congestion payment). in the eastern and southern control zones will incur a congestion charge (positive load congestion payment). The reverse is true for generation congestion credits. congestion credits, when positive, measure the total congestion credit to generation in an area. congestion credits, when negative, measure the total congestion cost to generation in an area. Negative generation congestion credits are a cost in the sense that revenues to generators in the area are lower, by the amount of the congestion cost, than they would have been if they had been paid LMP without a congestion component, the total of system marginal price and the loss component. Negative generation congestion credits result when generation is on the lower priced side of a constraint or constraints. For example, congestion across the AP South interface means lower prices in the western control zones and higher prices in the eastern and southern control zones. in the western control zones will receive lower prices and incur a congestion charge (negative generation congestion credit). in the eastern and southern control zones will receive higher prices and receive a congestion credit (positive generation congestion credit). As an example, total congestion costs in PJM in 2011 were $998.2 million, which was comprised of load congestion payments of $112.2 million, negative generation credits of $1,009.9 million and negative explicit congestion of $123.8 million (Table 10 15). Locational Marginal Price (LMP) s As of June 1, 2007, PJM changed from a single node reference bus to a distributed load reference bus. While there is no effect on the total LMP, the components of LMP change with a shift in the reference bus. With a distributed load reference bus, the energy component is now a load-weighted system price. There are no congestion or losses included in the load weighted reference bus price, unlike the case with a single node reference bus. Locational Marginal Price (LMP) at a bus reflects the incremental price of energy at that bus. LMP at any bus is made up of three basic components: the system marginal price (SMP), marginal loss component of LMP (MLMP), and congestion component of LMP (CLMP). SMP, MLMP and CLMP are a product of the least cost, security constrained dispatch of system resources to meet system load. SMP is the incremental cost of energy, given the current dispatch, ignoring incremental considerations of losses and transmission constraints. Losses refer to energy lost to physical resistance in the transmission and distribution network as power is moved from generation to load. The greater the resistance of the system to flows of energy from generation to loads, the greater the losses of the system and the greater the proportion of energy needed to meet a given level of load. Marginal losses are the incremental change in system power losses caused by changes in the system load and generation patterns. 15 The first derivative of total losses with respect to the power flow equals marginal losses, which are twice the average losses for that power flow. The term congestion is related to physical limitations of elements of the transmission system to move power from point to point. Congestion cost reflects the incremental cost of relieving transmission constraints while maintaining system power balance. Congestion occurs when available, least-cost energy cannot be delivered to all loads for a period because transmission facilities are not adequate to deliver that energy. When the leastcost available energy cannot be delivered to load in a transmission-constrained area, higher cost units in the constrained area must be dispatched to meet that load. 16 The result is that the price of energy in the constrained area is higher than in the unconstrained area because of the combination of transmission limitations and the cost of local generation. Table 10 1 shows the PJM real-time, load-weighted average LMP components for calendar years 2008 to The PJM price is weighted by accounting load, which differs from the state-estimated load used in determination of the energy component (SMP). The components of the average PJM system price result from these different weights. The load-weighted average realtime LMP in 2011 decreased $2.41 or 5.0 percent from $48.35 in 2010 to $45.94 in The load-weighted average congestion component decreased $0.03 or 34.4 percent from $0.08 in 2010 to $0.05 in The loadweighted average loss component decreased $0.01 or 15 For additional information, see the MMU Technical Reference for PJM Markets, at Marginal Losses. 16 This is referred to as dispatching units out of economic merit order. Economic merit order is the order of all generator offers from lowest to highest cost. Congestion occurs when loadings on transmission facilities mean the next unit in merit order cannot be used and a higher cost unit must be used in its place. 266 Section 10 Congestion and Marginal Losses

7 Section 10 Congestion and Marginal Losses 34.8 percent from $0.04 in 2010 to $0.02 in The load-weighted average energy component decreased $2.37 or 4.9 percent from $48.23 in 2010 to $45.87 in In terms of proportion of real-time LMP, the congestion and loss components both decreased, while the energy component became a greater proportion in Table 10 1 PJM real-time, load-weighted average LMP components (Dollars per MWh): Calendar years 2008 to Real-Time LMP Energy Congestion 2008 $71.13 $71.02 $0.06 $ $39.05 $38.97 $0.05 $ $48.35 $48.23 $0.08 $ $45.94 $45.87 $0.05 $0.02 Loss In the Real-Time Energy Market, the distributed load reference bus is weighted by system estimates of the load in real time. At the time the LMP is determined in the Real-Time Energy Market, the energy component equals the system load-weighted price. However, realtime bus-specific loads are adjusted, after the fact, according to updated information from meters. This meter adjusted load is accounting load that is used in settlements and forms the basis of the reported PJM load weighted prices. This after the fact adjustment means that the Real-Time Energy Market energy component of LMP (SMP) and the PJM real-time load-weighted LMP are not equal, as reported here. The difference between the real-time energy component of LMP and the PJM-wide real-time load-weighted LMP is due to the difference between estimated and meter corrected loads used to weight the load-weighted reference bus and the load-weighted LMP. Table 10 2 shows the PJM day-ahead, load-weighted average LMP components for calendar years 2008 through The load-weighted average day-ahead LMP in 2011 decreased $2.46 or 5.2 percent from $47.65 in 2010 to $45.19 in The load-weighted average congestion component decreased $0.11 or percent from $0.05 in 2010 to -$0.06 in The load-weighted average loss component decreased $0.08 or percent from -$0.07 in 2010 to -$0.15 in The loadweighted average energy component decreased $2.27 or 4.8 percent from $47.67 in 2010 to $45.40 in In 17 The years 2006 and 2007 were removed from Table 2-20 and Table 2-24 because PJM did not begin to include marginal losses in economic dispatch and LMP models until June 1, terms of proportion of day-ahead LMP, the congestion and loss components both decreased, while the energy component became a greater proportion in Table 10 2 PJM day-ahead, load-weighted average LMP components (Dollars per MWh): Calendar years 2008 to 2011 Day-Ahead LMP Energy Congestion Loss 2008 $70.25 $70.56 ($0.08) ($0.22) 2009 $38.82 $38.96 ($0.04) ($0.09) 2010 $47.65 $47.67 $0.05 ($0.07) 2011 $45.19 $45.40 ($0.06) ($0.15) In the Day-Ahead Energy Market, the distributed load reference bus is weighted by fixed-demand bids only and the day-ahead energy component is, therefore, a system fixed demand weighted price. The day-ahead weighted system price calculation uses all types of demand, including fixed, price-sensitive and decrement bids. In the Real-Time Energy Market, the energy component equals the system load-weighted price. However, in the Day-Ahead Energy Market the day-ahead energy component of LMP and the PJM day-ahead loadweighted LMP are not equal. The difference between the day-ahead energy component of LMP and the PJM dayahead load-weighted LMP is due to the difference in the types of demand used to weight the load-weighted reference bus and the load-weighted LMP. Zonal s The components of LMP were calculated for each PJM control zone. The components of LMP for the control zones are presented in Table 10 3 and Table 10 4 for calendar years 2010 and Table 10 3 shows the real-time load-weighted average LMP components by zone and PJM for calendar years 2010 and Price separation between eastern and western control zones in PJM was primarily a result of congestion on the AP South interface. This constraint generally had a positive congestion component of LMP in eastern and southern control zones located on the constrained side of the affected facilities while the unconstrained western zones had a negative congestion component of LMP. Table 10 4 shows the day-ahead load-weighted average LMP components by zone and PJM for calendar years 2010 and State of the Market Report for PJM 267

8 2011 State of the Market Report for PJM Table 10 3 Zonal and PJM real-time, load-weighted average LMP components (Dollars per MWh): Calendar years 2010 and Real-Time LMP Energy Congestion Loss Real-Time LMP Energy Congestion Loss AECO $57.03 $49.69 $3.87 $3.47 $57.81 $50.11 $4.95 $2.75 AEP $40.35 $47.45 ($4.67) ($2.43) $42.97 $48.64 ($3.99) ($1.68) AP $47.08 $47.42 ($0.05) ($0.28) $48.57 $48.99 ($0.22) ($0.20) ATSI NA NA NA NA $46.88 $51.24 ($3.85) ($0.51) BGE $59.19 $48.69 $8.04 $2.46 $58.74 $49.82 $6.62 $2.30 ComEd $36.21 $47.95 ($8.85) ($2.90) $38.97 $49.12 ($7.32) ($2.83) DAY $40.51 $48.10 ($6.66) ($0.93) $43.90 $49.40 ($4.57) ($0.93) DLCO $39.41 $47.89 ($6.68) ($1.79) $43.30 $49.12 ($4.15) ($1.67) Dominion $56.08 $48.86 $6.30 $0.92 $54.47 $49.83 $4.04 $0.60 DPL $56.51 $49.07 $4.59 $2.85 $56.76 $49.95 $3.82 $2.99 JCPL $56.00 $49.58 $3.92 $2.51 $58.09 $50.73 $4.62 $2.74 Met-Ed $53.47 $48.20 $4.22 $1.05 $53.64 $49.22 $3.42 $1.00 PECO $53.60 $48.36 $3.54 $1.70 $55.19 $49.47 $3.82 $1.90 PENELEC $45.17 $47.19 ($1.73) ($0.28) $48.18 $48.27 ($0.46) $0.37 Pepco $58.16 $48.70 $7.94 $1.51 $55.71 $49.82 $4.63 $1.26 PPL $51.50 $47.90 $2.84 $0.76 $53.76 $48.95 $3.85 $0.96 PSEG $55.78 $48.58 $4.73 $2.47 $57.16 $49.71 $4.78 $2.67 RECO $54.85 $49.48 $3.20 $2.17 $53.17 $50.88 ($0.15) $2.44 PJM $48.35 $48.23 $0.08 $0.04 $49.48 $49.40 $0.05 $0.03 Table 10 4 Zonal and PJM day-ahead, load-weighted average LMP components (Dollars per MWh): Calendar years 2010 and Day-Ahead LMP Energy Congestion Loss Day-Ahead LMP Energy Congestion Loss AECO $57.03 $49.69 $3.87 $3.47 $57.45 $49.53 $4.67 $3.25 AEP $40.35 $47.45 ($4.67) ($2.43) $42.90 $48.10 ($3.25) ($1.96) AP $47.08 $47.42 ($0.05) ($0.28) $47.66 $47.96 ($0.16) ($0.15) ATSI NA NA NA NA $46.14 $50.87 ($3.07) ($1.66) BGE $58.37 $48.37 $6.80 $3.20 $57.10 $49.19 $5.16 $2.75 ComEd $35.48 $47.12 ($7.62) ($4.02) $38.12 $48.12 ($6.46) ($3.55) DAY $40.18 $47.71 ($5.52) ($2.01) $43.25 $48.64 ($4.21) ($1.18) DLCO $40.03 $47.49 ($5.26) ($2.20) $42.60 $48.39 ($4.13) ($1.67) Dominion $56.08 $48.48 $6.05 $1.54 $53.16 $49.11 $3.35 $0.70 DPL $55.76 $48.66 $3.73 $3.37 $56.97 $49.29 $4.20 $3.48 JCPL $55.07 $48.61 $3.13 $3.32 $56.24 $49.45 $3.73 $3.06 Met-Ed $52.78 $47.72 $3.70 $1.35 $52.37 $48.08 $3.28 $1.01 PECO $53.63 $47.94 $3.18 $2.51 $55.35 $48.61 $4.33 $2.41 PENELEC $45.52 $46.41 ($0.88) ($0.00) $47.41 $47.72 ($0.56) $0.24 Pepco $56.41 $47.24 $6.85 $2.32 $54.99 $48.72 $4.49 $1.79 PPL $50.92 $47.45 $2.51 $0.95 $52.82 $48.27 $3.63 $0.93 PSEG $54.99 $48.02 $3.47 $3.50 $56.24 $48.89 $4.27 $3.09 RECO $55.56 $49.69 $2.67 $3.20 $53.55 $49.45 $1.75 $2.35 PJM $47.65 $47.67 $0.05 ($0.07) $48.34 $48.55 ($0.05) ($0.16) Energy Costs Energy Accounting The energy component of LMP is the system reference bus LMP, also called the system marginal price (SMP). The energy charge is based on the applicable day-ahead and real-time energy component of LMP (SMP). energy charges are equal to the load energy payments minus generation energy credits, plus explicit energy charges, incurred in both the Day-Ahead Energy Market and the balancing energy market. Due to losses, total generation will be greater than total load in any hour. Since the hourly integrated energy component of LMP is the same across the every bus in every hour, the net energy bill is negative, with more generation credits than load charges in any given hour. This net energy bill is netted against total net marginal loss charges plus net residual market adjustments, which 268 Section 10 Congestion and Marginal Losses

9 Section 10 Congestion and Marginal Losses provides for full recovery of generation charges, with any remainder distributed back to load and exports as marginal loss credits. Day-Ahead Energy. Day-ahead, load energy payments are calculated for all cleared demand, decrement bids and Day-Ahead Energy Market sale transactions. (Decrement bids and energy sales can be thought of as scheduled load.) Day-ahead, load energy payments are calculated using MW and the load bus energy component of LMP (energy LMP), the decrement bid energy LMP or the energy LMP at the source of the sale transaction, as applicable. Day-Ahead Energy Credits. Day-ahead, generation energy credits are calculated for all cleared generation and increment offers and Day- Ahead Energy Market purchase transactions. (Increment offers and energy purchases can be thought of as scheduled generation.) Day-ahead, generation energy credits are calculated using MW and the generator bus energy LMP, the increment offer energy LMP or the energy LMP at the sink of the purchase transaction, as applicable. Balancing Energy. Balancing, load energy payments are calculated for all deviations between a PJM member s real-time load and energy sale transactions and their day-ahead cleared demand, decrement bids and energy sale transactions. Balancing, load energy payments are calculated using MW deviations and the real-time energy LMP for each bus where a deviation exists. Balancing Energy Credits. Balancing, generation energy credits are calculated for all deviations between a PJM member s real-time generation and energy purchase transactions and the day-ahead cleared generation, increment offers and energy purchase transactions. Balancing, generation energy credits are calculated using MW deviations and the real-time energy LMP for each bus where a deviation exists. Explicit Energy. Explicit energy charges are the net energy charges associated with pointto-point energy transactions. These charges equal the product of the transacted MW and energy LMP differences between sources (origins) and sinks (destinations) in the Day-Ahead Energy Market. Balancing energy market explicit energy charges equal the product of the differences between the real-time and day-ahead transacted MW and the differences between the real-time energy LMP at the transactions sources and sinks. The explicit energy charges will sum to zero because the LMP (SMP) at the transactions sources and sinks will be the same for each transaction. Inadvertent Energy. Inadvertent energy charges are energy charges resulting from the differences between the net actual energy flow and the net scheduled energy flow into or out of the PJM control area each hour. This inadvertent interchange of energy may be positive or negative, where positive interchange typically results in a charge while negative interchange typically results in a credit. Inadvertent energy charges are common costs, not directly attributable to specific participants, that are distributed on a load ratio basis. 18 Calendar Year Energy Costs charges decreased 2.1 percent from 6.5 percent in 2010 to 4.4 percent in 2011 of annual total PJM billings. 19 Table 10 5 shows type of charges by year for 2010 and Energy charges decreased by $3.7 million from $797.9 million in 2010 to $794.2 million in Table 10 5 annual PJM charges by component (Dollars (Millions)): Calendar years 2010 and PJM Billing (millions) Energy Loss Congestion PJM Billing Percent of PJM Billing 2010 ($798) $1,635 $1,424 $2,261 $34, % 2011 ($794) $1,380 $998 $1,583 $35, % ($1,592) $3,014 $2,422 $3,844 $70, % energy charges are shown in Table 10 6 and Table Table 10 6 shows the 2010 and 2011 PJM energy costs by category. Table 10 7 shows the 2010 and 2011 PJM energy costs by market category. The 2011 PJM total energy costs were comprised of $47,656.9 million in load energy payments, $48,478.9 million in generation energy credits, $0.0 million in explicit energy charges and $27.8 million in inadvertent energy charges. 18 OA. Schedule 1 (PJM Interchange Energy Market) Calculated values shown in Section 10, Congestion and Marginal Losses, are based on unrounded, underlying data and may differ from calculations based on the rounded values in the tables. 20 The Energy, Loss and Congestion include net inadvertent charges State of the Market Report for PJM 269

10 2011 State of the Market Report for PJM Table 10 6 annual PJM energy costs by category (Dollars (Millions)): Calendar years 2010 and 2011 Energy Costs (Millions) Inadvertent Year Credits Explicit 2010 $53,101.4 $53,886.8 $0.0 ($12.5) ($797.9) 2011 $47,656.9 $48,478.9 $0.0 $27.8 ($794.2) Monthly Energy Costs Table 10 8 shows a monthly summary of energy costs by type for The highest monthly energy cost was in July and totaled -$120.1 million or 15.1 percent of the total. The majority of the energy costs was in the Day-Ahead Energy Market and totaled -$735.1 million. The day-ahead costs were offset, in part, by a total of -$86.9 million in the balancing market. Marginal Losses Marginal Loss Accounting With the implementation of marginal loss pricing, PJM calculates transmission loss charges for each PJM member. The loss charge is based on the applicable dayahead and real-time loss component of LMP (MLMP). Each PJM member is charged for the cost of losses on the transmission system, based on the difference between the MLMP at the location where the PJM member injects energy and the MLMP where the PJM member withdraws energy. More specifically, total loss charges are equal to the load loss payments minus generation loss credits, plus explicit loss charges, incurred in both the Day-Ahead Energy Market and the balancing energy market. Day-Ahead Loss. Day-ahead, load loss payments are calculated for all cleared demand, decrement bids and Day-Ahead Energy Market sale transactions. (Decrement bids and energy sales can be thought of as scheduled load.) Day-ahead, load loss payments are calculated using MW and the load bus loss component of LMP (MLMP), the decrement bid MLMP or the MLMP at the source of the sale transaction, as applicable. Day-Ahead Loss Credits. Day-ahead, generation loss credits are calculated for all cleared generation and increment offers and Day-Ahead Energy Market purchase transactions. (Increment offers and energy purchases can be thought of as scheduled generation.) Day-ahead, generation loss credits are calculated using MW and the generator Table 10 7 annual PJM energy costs by market category (Dollars (Millions)): Calendar years 2010 and 2011 Energy Costs (Millions) Balancing Inadvertent 2010 $53,164.8 $53,979.1 $0.0 ($814.3) ($63.4) ($92.3) $0.0 $28.9 ($12.5) ($797.9) 2011 $48,142.3 $48,877.4 $0.0 ($735.1) ($485.3) ($398.4) $0.0 ($86.9) $27.8 ($794.2) Table 10 8 Monthly energy costs by type (Dollars (Millions)): Calendar year 2011 Energy Costs (Millions) Balancing Inadvertent Jan $5,274.1 $5,364.4 $0.0 ($90.3) ($51.6) ($46.4) $0.0 ($5.2) $2.1 ($93.3) Feb $3,465.4 $3,526.5 $0.0 ($61.1) ($29.1) ($26.7) $0.0 ($2.4) $2.3 ($61.2) Mar $3,313.4 $3,365.7 $0.0 ($52.4) ($31.0) ($25.6) $0.0 ($5.4) $2.4 ($55.3) Apr $3,073.2 $3,123.1 $0.0 ($49.9) ($10.5) ($10.1) $0.0 ($0.4) $2.5 ($47.8) May $3,588.3 $3,643.0 $0.0 ($54.8) ($0.7) ($0.5) $0.0 ($0.2) $2.9 ($52.1) Jun $4,968.7 $5,050.8 $0.0 ($82.1) ($37.4) ($34.2) $0.0 ($3.2) $1.2 ($84.2) Jul $7,010.4 $7,120.4 $0.0 ($110.0) ($87.7) ($71.0) $0.0 ($16.8) $6.7 ($120.1) Aug $4,713.0 $4,779.8 $0.0 ($66.9) ($65.8) ($49.4) $0.0 ($16.4) $4.9 ($78.3) Sep $3,499.2 $3,554.2 $0.0 ($55.0) ($78.6) ($73.2) $0.0 ($5.5) $1.1 ($59.4) Oct $3,110.0 $3,152.7 $0.0 ($42.7) ($46.1) ($40.2) $0.0 ($5.9) $0.3 ($48.3) Nov $2,935.8 $2,966.0 $0.0 ($30.2) ($12.8) $1.8 $0.0 ($14.6) $0.8 ($44.0) Dec $3,191.0 $3,230.6 $0.0 ($39.6) ($34.1) ($23.0) $0.0 ($11.0) $0.6 ($50.1) $48,142.3 $48,877.4 $0.0 ($735.1) ($485.3) ($398.4) $0.0 ($86.9) $27.8 ($794.2) 270 Section 10 Congestion and Marginal Losses

11 Section 10 Congestion and Marginal Losses bus MLMP, the increment offer MLMP or the MLMP at the sink of the purchase transaction, as applicable. Balancing Loss. Balancing, load loss payments are calculated for all deviations between a PJM member s real-time load and energy sale transactions and their day-ahead cleared demand, decrement bids and energy sale transactions. Balancing, load loss payments are calculated using MW deviations and the real-time MLMP for each bus where a deviation exists. Balancing Loss Credits. Balancing, generation loss credits are calculated for all deviations between a PJM member s real-time generation and energy purchase transactions and the day-ahead cleared generation, increment offers and energy purchase transactions. Balancing, generation loss credits are calculated using MW deviations and the real-time MLMP for each bus where a deviation exists. Explicit Loss. Explicit loss charges are the net loss charges associated with point-to-point energy transactions. These charges equal the product of the transacted MW and MLMP differences between sources (origins) and sinks (destinations) in the Day-Ahead Energy Market. Balancing energy market explicit loss charges equal the product of the differences between the real-time and dayahead transacted MWs and the differences between the real-time MLMP at the transactions sources and sinks. Inadvertent Loss. Inadvertent loss charges are loss charges resulting from the differences between the net actual energy flow and the net scheduled energy flow into or out of the PJM control area each hour. This inadvertent interchange of energy may be positive or negative, where positive interchange typically results in a charge while negative interchange typically results in a credit. Inadvertent loss charges are common costs, not directly attributable to specific participants, that are distributed on a load ratio basis. 21 Marginal loss charges can be both positive and negative and consequently the load payments and generation credits can also be both positive and 21 OA. Schedule 1 (PJM Interchange Energy Market) 3.7 negative. The loss component of LMP is calculated with respect to the system reference bus LMP, also called the system marginal price (SMP). An increase in generation at a bus that results in an increase in losses will cause the marginal loss component of that bus to be negative. If the increase in generation at the bus results in a decrease of system losses, then the marginal loss component is positive. Calendar Year Marginal Loss Costs Loss charges decreased by 0.9 percent from 4.7 percent in 2010 to 3.8 percent in 2011 of annual total PJM billings. 22 Table 10 9 shows total marginal loss charges by year for 2010 and Loss charges decreased by $255.3 million from $1,634.8 million in 2010 to $1,379.5 million in Table 10 9 annual PJM Marginal Loss (Dollars (Millions)): Calendar years 2010 and 2011 Loss Percent Change PJM Billing Percent of PJM Billing 2010 $1,635 NA $34, % 2011 $1,380 (15.6%) $35, % $3,014 $70, % marginal loss costs for 2010 and 2011 are shown in Table and Table Table shows the 2011 PJM marginal loss costs by category and Table shows the 2011 PJM marginal loss costs by market category. The 2011 PJM total marginal loss costs were comprised of -$174.0 million in load loss payments, -$1,551.9 million in generation loss credits, $1.6 million in explicit loss costs and $12,775.2 in inadvertent loss charges. Table annual PJM marginal loss costs by category (Dollars (Millions)): Calendar years 2010 and 2011 Marginal Loss Costs (Millions) Year Credits Explicit Inadvertent 2010 ($122.3) ($1,707.0) $50.2 ($0.0) $1, ($174.0) ($1,551.9) $1.6 $0.0 $1, Calculated values shown in Section 10, Congestion and Marginal Losses, are based on unrounded, underlying data and may differ from calculations based on the rounded values in the tables State of the Market Report for PJM 271

12 2011 State of the Market Report for PJM Table annual PJM marginal loss costs by market category (Dollars (Millions)): Calendar years 2010 and 2011 Marginal Loss Costs (Millions) Balancing Inadvertent 2010 ($146.3) ($1,716.1) $95.8 $1,665.6 $23.9 $9.1 ($45.6) ($30.7) ($0.0) $1, ($215.4) ($1,592.1) $53.8 $1,430.5 $41.3 $40.2 ($52.2) ($51.0) $0.0 $1,379.5 Table Monthly marginal loss costs by type (Dollars (Millions)): Calendar year 2011 Marginal Loss Costs (Millions) Balancing Inadvertent charges Jan ($16.6) ($192.8) $12.3 $188.5 $5.3 $2.8 ($5.4) ($2.9) $0.0 $185.7 Feb ($9.9) ($124.8) $6.8 $121.8 $3.3 $3.2 ($1.9) ($1.8) $0.0 $119.9 Mar ($10.5) ($112.5) $6.8 $108.8 $2.0 $3.0 ($3.8) ($4.8) $0.0 $104.0 Apr ($10.3) ($91.6) $3.4 $84.8 $1.7 $2.3 ($5.1) ($5.6) $0.0 $79.2 May ($8.6) ($93.9) $9.0 $94.3 $3.3 $3.2 ($7.1) ($7.0) $0.0 $87.3 Jun ($34.4) ($158.4) $5.9 $129.9 $4.2 $4.4 ($4.3) ($4.5) $0.0 $125.4 Jul ($40.0) ($254.3) $3.1 $217.4 $8.4 $8.3 ($3.8) ($3.7) $0.0 $213.7 Aug ($25.3) ($162.1) $1.2 $137.9 $2.0 $2.7 ($2.7) ($3.5) $0.0 $134.5 Sep ($18.6) ($123.1) $3.1 $107.7 $5.4 $6.2 ($3.9) ($4.7) $0.0 $102.9 Oct ($9.8) ($93.5) $2.0 $85.7 $1.7 $1.3 ($4.1) ($3.6) $0.0 $82.0 Nov ($15.9) ($93.5) ($1.6) $76.0 $1.6 $0.5 ($2.9) ($1.7) $0.0 $74.3 Dec ($15.4) ($91.5) $1.6 $77.8 $2.6 $2.4 ($7.3) ($7.1) $0.0 $70.6 ($215.4) ($1,592.1) $53.8 $1,430.5 $41.3 $40.2 ($52.2) ($51.0) $0.0 $1,379.5 Monthly Marginal Loss Costs Table shows a monthly summary of marginal loss costs by type for The highest monthly loss cost was in July and totaled $213.7 million or 15.5 percent of the total. The majority of the marginal loss costs was in the Day-Ahead Energy Market and totaled $1,430.5 million. The day-ahead costs were offset, in part, by a total of -$51.0 million in the balancing market. Marginal Loss Costs and Loss Credits Marginal loss credits (loss surplus) are calculated by adding the total net energy costs, the total net marginal loss costs and net residual market adjustments. The total energy costs are equal to the net energy costs (generation energy credits less load energy payments plus net inadvertent energy charges plus net explicit energy charges). marginal loss costs are equal to the net marginal loss costs (generation loss credits less load loss payments plus net inadvertent loss charges plus net explicit loss charges). Ignoring interchange, the existence of losses will cause total generation to be greater than total load in any hour. Since the hourly integrated energy component of LMP is the same across every generator and load bus in every hour, the net energy bill will be negative (ignoring net interchange), with more generation credits than load charges collected in any given hour. This net energy bill is netted against total net marginal loss charges and net residual market adjustments, with the remainder distributed back to load and exports as marginal loss credits. Residual market adjustments consist of the known day-ahead error value, day-ahead loss MW congestion value and balancing loss MW congestion value. The known day-ahead error value is the financial calculation for the MW imbalance created when the day-ahead case is solved. The dayahead and balancing loss MW congestion values are congestion values associated with loss MW that need to be deducted from the net of the total marginal loss costs, total energy costs and day-ahead known error value before marginal loss credits can be distributed. Table shows the total net energy charges, the total net marginal loss charges collected, the net residual 272 Section 10 Congestion and Marginal Losses