Five-Minute Settlements Education

Transcription

1 Five-Minute Settlements Education

2 Disclaimer PJM has made all efforts possible to accurately document all information in this presentation. The information seen here does not supersede the PJM Operating Agreement or the PJM Tariff or any pending FERC Filings or Orders. 2

3 Welcome & Introduction Revenue Data for Settlements PowerMeter Break Energy Market Ancillary Services (Regulation, Synchronized Reserve, & Non-Synchronized Reserve) Lunch Uplift Credits & Charges Break Load Response Capacity Performance FERC EQR & Data Miner Closing 9:00 am 9:15 am 9:15 am 9:45 am 9:45 am 10:15 am 10:15 am 10:30 am 10:30 am 11:15 am 11:15 am 12:00 pm 12:00 pm 1:00 pm 1:00 pm 1:45 pm 1:45 pm 2:00 pm 2:00 pm 2:30 pm 2:30 pm 2:45 pm 2:45 pm 2:55 pm 2:55 pm 3:00 pm Agenda 3

4 Introduction

5 Energy Transactions Order 825: Settle Real-Time energy transactions at same interval they are dispatched Day-Ahead Energy Clearing process unchanged Day-Ahead prices and MWh schedules remain hourly For balancing settlements, Day-Ahead hourly MWh and prices are evenly distributed for each 5- minute interval Real-Time Energy Settle using 5-minute LMPs Generation: Use either 5-minute meter data or profile hourly revenue data by State Estimator values Load: Use hourly average for all 5-minute intervals Demand Response: Use hourly curtailment values evenly over curtailment period Load and Demand Response: No change Generation: Hourly or optional 5-minute Day-Ahead: No change Real-Time: 5-minute values for settlements 5

6 Reserves & Intertie Transactions Order 825: Settle Real-Time ancillary service transactions at same interval they are priced Commitment process unchanged Settle using 5-minute LMPs and Regulation Market Clearing Prices (MCPs) Commitment process unchanged Settle using 5-minute LMPs, SRMCP, and NSRMCP Order 825: Settle intertie transactions at same interval they are scheduled Settle using three, 5-minute LMPs within 15-minute transaction interval 6

7 Project Roadmap Q Q Q Q Q PJM Compliance Filing Design, Development, Testing Training Implementation Production Implementation Settlements Obtain Member Feedback on App Changes Communicate Power Meter Changes Communicate MSRS Changes 7

8 Market Trials Customer Documentation Available for 40 Reports Nov 3 Day-Ahead & Balancing Market Reports in Training Environment with Production Results Nov 20 Load Response Reports in Training Environment with Production Results TBD Ancillary Services Reports in Training Environment with Production Results TBD Go Live Apr Nov Dec 2018 Feb Mar Apr 2018 Nov 30 MSRS Reports in Training Environment with Static Data TBD Operating Reserve Reports in Training Environment with Production Results 8

9 Revenue Data for Settlements

10 Revenue Data for Settlements Energy quantities used in accounting and billing to calculate Spot Market Energy charges Transmission Congestion charges Transmission Loss charges Ancillary Services credits Operating Reserve credits and charges Three approaches, depending on resource type and metering capability of resource 10

11 Revenue Data for Settlements Methodologies Revenue Meter Data (Generation Resources, including Pseudo- Tie Generators that Provide Revenue Data) Revenue data must meet accuracy standards in PJM Manuals If Market Participants submitted revenue meter data on 5-minute basis, must continue to provide revenue meter data for resource Optional Telemetry Data, Adjusted (Generation Resources, including Pseudo- Tie Generators that Provide Hourly Revenue Data) Use real-time telemetry data or State Estimator values Apply scaling factor Conduct Hourly Tolerance Check Flat Profile (Demand Response Resources, Load, Imports/Exports, Internal Bilateral Transactions & Generation Resources that Do Not Provide Real-time Telemetry) Determine equal values for each 5-minute interval within applicable period Results in 5-minute settlements that are equivalent to today s settlements, but divided by number of 5-minute intervals in applicable time period 11

12 Scaled, Hourly Revenue Meter Data PJM uses either 5-minute telemetry values or 5-minute state estimator values, whichever is closest to revenue meter data Hourly Tolerance Check Fails if. Difference between average of 5-minute telemetry values or state estimator values and hourly revenue meter data is > 20% of hourly revenue meter data AND > 10 MWh 12

13 Real-Time Generator Scaling & Balancing Interval Number SE MW RT 5 MIN Allocation Total DA MW 5 Min Bal Deviation RT LMP ($/MWh) BAL Credit Settlement Balancing Credit ($904.10) ($75.34) ($459.60) ($38.30) ($45.37) ($3.78) ($213.82) ($17.82) ($199.98) ($16.66) ($661.67) ($55.14) ($491.91) ($40.99) ($297.51) ($24.79) ($4.50) ($0.37) ($5.25) ($0.44) ($187.98) ($15.66) ($102.67) ($8.56) ($297.86) (5-Min Bal Deviation * RT LMP) / 12 Power Meter MW = 178 Scaling Factor = PM MWh / SE MW avg = 178 / = For Interval 1: RT 5 MIN Allocation = SE MW * Scaling Factor = 165 * = MW 5 Min Settlement Balancing Credit = (5 Min Bal Deviation * RT LMP) / 12 = ( * $37) / 12 = -$75.34 Total Balancing 5 Min Settlement Balancing Credit Intervals 1-12 = -$ Status Quo Balancing Credit = (RT MWh - DA MWh) * RT LMP = ( ) * $44.75 = -$ Note this example assumes state estimator data is used for scaling 13

14 OLD Hour Ending 01: 100 MWh Load Hour Ending Load (MWh) LMP ($/MWh) Load or Internal Bilateral Transaction Flat Profile Example Hourly Settlement (Load * LMP) $39 $3, NEW Interval Begin Time Flat Profiled Load (MW) LMP ($/MWh) Settlement (Load * LMP)/12 : $18 $150 : $25 $208 : $29 $242 : $33 $275 : $38 $317 : $40 $333 : $45 $375 : $47 $392 : $48 $400 : $48 $400 : $48 $400 : $49 $408 Total for Hour Ending Load (MWh) LMP ($/MWh) Hourly Settlement Rollup $39 $3,

15 OLD Bid Price Net Benefits Threshold Reduction Hour Ending DR Actual MW Relief (MWh) $23.25/MWh $ /MWh MW LMP ($/MWh) Hourly Settlement (Relief * LMP) $24.20 $ Note example does not consider Operating Reserves for Demand Response Resources NEW Demand Response Flat Profile Example Interval Begin Time Flat Profiled DR Real-Time Response (MW) LMP ($/MWh) Settlement Real-time Response * LMP)/12 :00 $26 $0.00 :05 $28 $0.00 : $30 $21.17 : $24 $16.94 : $20 : $23 : $23 : $27 $19.05 : $25 $17.64 : $23 : $24 $16.94 : $25 $17.64 Total $

16 External Transaction Flat Profile Example OLD Hour Ending 01: 50 MWh Transaction Hour Ending Transaction (MWh) LMP ($/MWh) Hourly Settlement (Transaction * LMP) $39 $1,950 Total $1,950 NEW Interval Begin Time NERC Tag Profiled RT Transaction (MW) LMP ($/MWh) Settlement (Transaction * LMP)/12 :00 0 $18 $0 :05 0 $25 $0 :10 0 $29 $0 : $33 $275 : $38 $317 : $40 $333 : $46 $383 : $47 $392 : $48 $400 :45 0 $48 $0 :50 0 $48 $0 :55 0 $48 $0 Total $2,100 16

17 Appendix

18 Σ (Telemetry Values) * (Time Duration/5 Minutes) Calculate Time- Weighted Telemetry Values Calculate Time- Weighted State Estimator Value Scaled, Hourly Revenue Meter Data Σ (State Estimator Values) * (Time Duration/5 Minutes) Σ (Time Weighted Telemetry Values) / 12 Calculate Hourly- Integrated Telemetry MWh Value Calculate Hourly- Integrated State Estimator MWh Value Σ (Time Weighted State Estimator Values) / 12 Hourly Revenue Meter MWh / Hourly Integrated Telemetry MWh Calculate Telemetry Scaling Factor Calculate State Estimator Scaling Factor Hourly Revenue Meter MWh / Hourly Integrated State Estimator MWH Lessor of { 1 Telemetry Scaling Factor OR 1 State Estimator Scaling Factor } Use Telemetry or State Estimator Scaling Factor? If values are equal, then PJM uses Time- Weighted Telemetry MW values Fails if Hourly Integrated Telemetry MWh Hourly Revenue Meter MWh / Hourly Revenue Meter MWh is > 20% AND Hourly Integrated Telemetry MWh Hourly Revenue Meter MWh > 10 MWh Yes Pass Tolerance Check? Telemetry No State Estimator No Pass Tolerance Check? Yes Fails if Hourly Integrated State Estimator MWh Hourly Revenue Meter MWh / Hourly Revenue Meter MWh is > 20% AND Hourly Integrated State Estimator MWh Hourly Revenue Meter MWh > 10 MWh Scaling Factor * Time Weighted Telemetry MW Use Time-Weighted Telemetry MW Values Flat Profile, Set to Hourly Revenue Meter MWh Flat Profile, Set to Hourly Revenue Meter MWh Use Time-Weighted State Estimator MW Values Scaling Factor * Time Weighted State Estimator MW 18

19 Power Meter

20 Power Meter Data Submission Options 1. Continue to submit hourly revenue meter data Hourly values scaled using 5-minute telemetry or State Estimator values to determine Revenue Data for Settlements for generator 2. Transition to 5-minute revenue meter data submissions Five-minute revenue meter data is Revenue Data for Settlements for generator 20

21 Requesting Meter Data Submissions Pre Go-Live Generation Resource Sends to PJM Market Settlements by 1700 on March 16, 2018 (for an Operating Day start of April 1, 2018) Sends to PJM Market Settlements after 1700 on March 16, 2018 through April 4, 2018 (for an Operating Day start no earlier than April 9, 2018) PJM Market Settlements Performs verification Notifies Generation Resource that resource is set-up in Power Meter Generation Resource Submits 5-minute revenue meter data on effective Operating Day 21

22 Requesting Meter Data Submissions Post Go-Live Generation Resource Sends to PJM Market Settlements at least 3 business days prior to Operating Day for which 5-minute revenue meter data is effective PJM Market Settlements Performs verification Notifies Generation Resource that resource is set-up in Power Meter Generation Resource Submits five minute revenue meter data on effective Operating Day 22

23 Power Meter Documentation 23

24 Daily Submission Screen 1. Maintain current screen in hourly format 2. New column added to identify if meter point is hourly or 5- minute If hourly, submitted value displayed If 5-minute, hourly integrated value displayed with no edit capability 3. Five-minute revenue meter data entered using XML upload through Command Line Interface (CLI) 4. New report to download 5-minute meter data in XML format 24

25 Daily Submission Screen New Column to identify if Meter Point is Hourly or 25

26 CSV Upload for Meter Data CSV Upload Template Date Meter ID Interval Ending in EPT MW Value Date 4/6/2017 ID Interval Ending Value 123 0: : : : : : : : : : : : : : :

27 CSV Download for Meter Data Options 1. Select meter point(s) to download all 5-minute intervals for selected date range through CLI 2. One click to download ALL 5-minute intervals for ALL meter points submitting 5-minute meter data from Reports screen based on selected date range 27

28 Energy Market

29 Discussion Topics Day-Ahead & Balancing Spot Market Energy Charges Day-Ahead & Balancing Transmission Congestion Charges & Credits Day-Ahead & Balancing Transmission Loss Charges & Credits Meter Error Correction Charges Emergency Energy Charges & Credits Energy Market Report Changes 29

30 Day-Ahead & Balancing Spot Market Energy Charges

31 Spot Market Energy Charge Change Highlights Settlement Interval Replace current hourly settlement interval in Real-Time Energy Market with 5-minute settlement interval, based on 5-minute LMPs that PJM already calculates and 5-minute energy quantities, using Revenue Data for Settlements Generation Use 5-minute telemetry profiled MW or 5- minute meter MW Load Use flat profile MW for hour Demand Response Use flat profile MW over actual dispatch timeframe Import/Export Use flat profile MW over 15-minute schedule Internal Bilateral Transaction Use flat profile MW for hour Day-Ahead Settlement Interval (hourly) Real-Time Settlement Interval (5-minute) $ MW Hour Hour 12 Interval $ MW (12 ) Interval 31

32 Spot Market Energy Charge Change Highlights (continued) Day-Ahead & Real-Time Transaction Positions Market Participant Energy Injection Day-ahead generation schedules, real-time generation output, increment offers, internal bilateral transactions (buyer), and import transactions Market Participant Energy Withdrawal Demand bids, decrement bids, real-time load, internal bilateral transactions (seller), and export transactions Charge calculation going forward uses concepts of participant injections and withdrawals, rather than Net Interchange Spot Market Energy Position is determined for each 5-minute interval 32

33 Day-Ahead Spot Market Energy Charge No change to hourly settlement interval Balancing Spot Market Energy Charge Five-minute settlement interval Spot Market Energy Charge Change Highlights (continued) Continue to settle based on deviation between Real-Time and Day-Ahead Spot Market Energy Markets PJM calculates 5-minute day-ahead quantities by flat profiling hourly day-ahead quantities over 5-minute intervals in hour Day-ahead imports can be scheduled sub-hourly and are set equal to MW value for each 5-minute interval transaction is scheduled and adjusted for any curtail in Day-Ahead Energy Market 33

34 Day-Ahead Spot Market Energy Charge Calculation Methodology 1200 Day-Ahead Spot Market Energy Existing Methodology Day-Ahead Net Interchange Hourly Day- Ahead System Energy Price Tariff - Attachment K Appendix; Section Settlement Methodology Hourly Day- Ahead Scheduled Energy Withdrawals Hourly Day- Ahead System Energy Price Hourly Day- Ahead Scheduled Energy Injections Hourly Day- Ahead System Energy Price 34

35 Balancing Spot Market Energy Calculation Methodology Comparison 1205 Balancing Spot Market Energy Existing Methodology Real-Time Net Interchange Day-Ahead Net Interchange Hourly Real- Time System Energy Price Tariff - Attachment K Appendix; Section Settlement Methodology Real-Time Energy Withdrawals Day-Ahead Scheduled Energy Withdrawals Real- Time System Energy Price 12 Real-Time Energy Injections Day-Ahead Scheduled Energy Injections Real- Time System Energy Price 12 35

36 Spot Market Energy Generation Example NEW 5- Minute Interval Begin DA Cleared (MW) Profiled Gen (MW) Balancing Deviation (MW) System Energy Price Balancing Spot Market Charge (RT Dev * System Energy Price/12) : $18 $300 : $25 $417 : $29 $483 : $33 $550 : $38 $633 : $40 $667 : $45 $375 : $47 $392 : $48 $400 : $48 $400 : $48 $400 : $49 $408 Generator clears 200 MWh in Day-Ahead Market Generator submits 50 MWh meter reading Generator submits 50 MWh meter reading Hour End Hour End Cleared Gen (MWh) Metered Gen (MWh) DA System Energy Price ($/MWh) Balancing Deviation (MWh) DA Spot Market Charge $30 -$6,000 RT System Energy Price ($/MWh) NO CHANGE Balancing Spot Market Charge $39 $5, Hour End Metered Gen (MWh) Balancing Deviation (MWh) RT System Energy Price ($/MWh) Balancing Spot Market Charge $39 $5,425 OLD NEW $5,425 Sum of 12 5-minute intervals 36

37 Spot Market Energy Load Example NEW Interval Begin Time DA Cleared (MW) Flat Profiled Load (MW) Balancing Deviation (MW) System Energy Price ($/MWh) Balancing Spot Market Charge (RT Dev * System Energy Price/12) : $18 $15 Load clears 90 MWh in Day-Ahead Market Hour End Cleared Load (MWh) DA System Energy Price ($/MWh) DA Spot Market Charge NO CHANGE : $25 $ $30 $2,700 : $29 $24 : $33 $28 : $38 $32 : $40 $33 Load 100 MWh Hour End Load (MWh) Balancing Deviation (MWh) RT System Energy Price ($/MWh) Balancing Spot Market Charge $39 $ OLD : $45 $38 : $47 $39 : $48 $40 : $48 $40 : $48 $40 : $49 $41 Load 100 MWh Hour End Metered Load (MWh) Balancing Deviation (MWh) RT System Energy Price ($/MWh) Balancing Spot Market Charge $39 $ NEW $ Sum of 12 5-minute intervals 37

38 External Transaction Example NEW Interval Begin Time DA Cleared Transaction (MW) NERC Tag Profiled RT Transaction (MW) Balancing Deviation System Energy Price ($/MWh) Balancing Spot Market Charge (Transaction * LMP)/12 : $18 $0.00 : $25 $0.00 : $29 $0.00 : $33 $ : $38 $ : $40 $ : $46 $38.33 : $47 $39.17 : $48 $40.00 : $48 -$ : $48 -$ : $48 -$ Total -$37.50 Transaction scheduled 90 MW for :30 thru :55; clears 45 MWh in Day-Ahead Market Transaction scheduled NERC tag for 100 MWh from :15 to :40 Transaction scheduled NERC tag for 100 MWh from :15 to :40 Hour End Hour Ending Hour End DA Cleared Transaction (MWh) RT Hourly Integrated Transaction (MWh) RT Hourly Integrated Transaction (MWh) DA System Energy Price ($/MWh) Balancing Deviation (MWh) Balancing Deviation (MWh) DA Spot Market Charge $30 $1, RT System Energy Price ($/MWh) RT System Energy Price ($/MWh) NO CHANGE OLD Balancing Spot Market Charge $39 $ NEW Balancing Spot Market Charge $39 -$37.50 Sum of minute intervals 38

39 Day-Ahead & Balancing Transmission Congestion Charges & Credits

40 Implicit Transmission Congestion Charges Change Highlights Transmission Implicit Congestion Charges Day-Ahead Implicit Congestion Charge No change to Day-Ahead zonal & residual aggregate definitions Calculation now performed at aggregate level, instead of breaking aggregation down to bus components Generation continues to use existing process Balancing Implicit Congestion Charge No change to Real-Time zonal & residual aggregate definitions Calculation now performed at aggregate level, instead of breaking aggregation down to bus components Calculation now uses 5-minute congestion prices Generation uses 5-minute congestion prices at generator bus 40

41 Implicit Congestion Charge Example Zone A DA Definitions DA MW based 100 RT MW based 100 Deviation (RT-DA) RT Congestion LMP Balancing Implicit C ti Bus 1 20% 20 MW 25 MW 5 15 $75.00 Bus 2 35% 35 MW 30 MW -5 5 ($25.00) Bus 3 5% 5 MW 10 MW 5 10 $50.00 Bus 4 15% 15 MW 10 MW -5 5 ($25.00) Bus 5 25% 25 MW 25 MW 0 10 $0.00 $75.00 Balancing Congestion Charge OLD Even though Market Participant is perfectly hedged between Day-Ahead and Real-Time at 100 MW, breaking Zone A down to bus level results in a $75 Balancing Implicit Congestion Charge. This charge is a result of the different definitions for Zone A between Day- Ahead and Real-Time. DA MW RT MW Deviation (RT-DA) Balancing Implicit C ti Zone A $0 NEW With zone or Residual Aggregate Market Participant is perfectly hedged between Day-ahead and Real-time for 100 MW! 41

42 Balancing Implicit Transmission Congestion Charge 1215 Balancing Transmission Congestion Existing Methodology Balancing Withdrawal Deviation MWh Balancing Injection Deviation MWh Hourly Real- Time Bus Congestion LMP Settlement Methodology Balancing Withdrawal Deviation MW Real-Time Bus or Aggregate Congestion LMP 12 Balancing Injection Deviation MW Real-Time Bus or Aggregate Congestion LMP 12 Tariff - Attachment K Appendix; Section

43 Transmission Congestion Charges Change Highlights (continued) Transmission Explicit Congestion Charges Day-Ahead Explicit Congestion Charge No change Hourly scheduled energy transactions MWh multiplied by delta of Day-Ahead sink and source congestion prices using Day-Ahead congestion aggregate prices Balancing Explicit Congestion Charge Five-minute deviations from Day-Ahead scheduled energy transactions MW multiplied by delta of Real-Time sink and source congestion prices, using Real- Time congestion 5-minute prices 43

44 Balancing Explicit Transmission Congestion Charge 1215 Balancing Transmission Congestion Existing Methodology Hourly Real- Time Congestion LMP at Sink Hourly Real- Time Congestion LMP at Source Hourly Transaction MWh Deviation Settlement Methodology Real-Time Congestion LMP at Sink 12 Real-Time Congestion LMP at Source Transaction MW Deviation Tariff - Attachment K Appendix; Section

45 Transmission Congestion Credit Change Highlights Transmission Congestion Credits No change Day-Ahead Congestion Credits allocated to FTR holders Balancing Congestion Credits allocated to Real-Time load and exports 45

46 Day-Ahead & Balancing Transmission Loss Charges & Credits

47 Transmission Loss Charges Change Highlights Transmission Implicit Loss Charge Day-Ahead Implicit Loss Charge No change to Day-Ahead zonal & residual aggregate definitions; Real-Time bus distribution as of HE08 one week prior to Operating Day Calculation now performed at aggregate level, instead of breaking aggregation down to bus components Generation continues using existing process Balancing Implicit Loss Charge No change to Real-Time zonal & aggregate definitions Calculation now uses 5-minute loss prices Generations continues to use 5-minute loss prices at generator bus 47

48 Balancing Implicit Transmission Loss Charge 1225 Balancing Transmission Losses Existing Methodology Balancing Withdrawal Deviation MWh Balancing Injection Deviation MWh Hourly Real- Time Loss LMP Settlement Methodology Balancing Withdrawal Deviation MW Real-Time Bus or Aggregate Loss LMP 12 Balancing Injection Deviation MW Real-Time Bus or Aggregate Loss LMP 12 Tariff - Attachment K Appendix; Section

49 Transmission Loss Charges Change Highlights (continued) Transmission Explicit Loss Charges Day-Ahead Explicit Loss Charges No change Hourly scheduled energy transactions MWh multiplied by delta of Day-Ahead sink and source loss prices using Day-Ahead loss aggregate prices Balancing Explicit Loss Charges Five-minute deviations from Day-Ahead scheduled energy transactions MWh multiplied by delta of Real-Time sink and source congestion prices, using Real- Time loss 5-minute prices 49

50 Balancing Explicit Transmission Loss Charge 1225 Balancing Transmission Losses Existing Methodology Hourly Real- Time Loss LMP at Sink Hourly Real- Time Loss LMP at Source Hourly Transaction MWh Deviation Settlement Methodology Real-Time Loss LMP at Sink 12 Real- Time Loss LMP at Source Transaction MWh Deviation Tariff - Attachment K Appendix; Section 5.4.4A 50

51 Transmission Loss Credits Change Highlights Transmission Loss Credits No change Total hourly Day-Ahead and Balancing Transmission Losses charges allocated on ratio share of Real-Time load (de-rated for transmission losses), plus exports that pay for transmission service 51

52 Meter Error Correction Charges

53 Generation Meter Error Correction Charges Meter Error Correction Change Highlights Use 5-minute interval generation-weighted LMP, rather than hourly generation weighted average LMP Meter Error Correction Periodicity No change Reconciled at end of month by meter correction charge (positive or negative) Tie Meter Error Correction Charges No change Monthly load-weighted average LMP 53

54 Emergency Energy Charges & Credits

55 Emergency Energy Change Highlights Emergency Energy Charges Five-minute costs of emergency energy purchased by PJM are allocated to Market Participants in proportion to their real-time deviations from day-ahead withdrawals and injections whenever deviation increases their spot market purchase or decreases their spot market sales Calculated for each 5-minute interval and then summed for hourly total Emergency Energy Credits Five-minute revenues from emergency energy sold by PJM are allocated to Market Participants in proportion to real-time deviations from day-ahead withdrawals and injections, whenever deviation increases their spot market purchases or decreases their spot market sales Calculated for each 5-minute interval and then summed for hourly total 55

56 Minimum Generation Energy Charges Minimum Generation Change Highlights Five-minute net cost of energy purchased is allocated to Market Participants in proportion to their real-time deviation from day-ahead withdrawals and injections, whenever that deviation decreases their spot market purchase or increases their spot market sales Calculated for each 5-minute interval and then summed for hourly total Minimum Generation Energy Credits Five-minute net revenues in connection with Minimum Generation Emergency energy sales to other Control Areas are credited to PJM Market Participants in proportion to their real-time deviation from day-ahead withdrawals and injections, whenever that deviation decreases their spot market purchases or increases their spot market sales. Calculated for each 5-minute interval and then summed for hourly total 56

57 Energy Market Report Changes

58 Energy Market Report Changes Report Spot Market Energy Charge Summary Energy Market and Congestion Loss Charge Details Explicit Congestion Charges Explicit Loss Charges Implicit Congestion and Loss Charge Details Generator LMP Charge Summary Balancing Generator LMP Charges Day-Ahead Daily Energy Transactions Changes Change to existing report that displays withdrawal and injection energy, instead of net interchange. Report no longer displays real-time energy price. New report that displays day-ahead and real-time spot market energy charges, implicit congestion charges, and implicit loss charges on sub-hourly basis. Change to existing report format that displays current data on sub-hourly basis. Change to existing report format that displays current data on sub-hourly basis. Report format terminates 4/1/18. Implicit congestion and implicit loss charges reported on sub-hourly basis on Energy Market and Congestion Loss Charge Details report. Change to existing report format of Generator LMP charges, no longer displays real-time prices. New report that displays balancing injection and withdrawal values and charges for generators on sub-hourly basis. Rename transaction type; changed transaction type label Total DA Net Interchange to Total DA Withdrawals - Injections. Report is otherwise unchanged and remains hourly. Real-Time Daily Energy Transactions Rename transaction type; changed transaction type label RT Net Interchange to RT Withdrawals - Injections. Report is otherwise unchanged and remains hourly. Settlements Reports 58

59 Ancillary Services

60 Discussion Topics Ancillary Services Change Highlights Regulation Charge & Credit Changes Synchronized Reserve Charge & Credit Changes Non-Synchronized Reserve Charge & Credit Changes Ancillary Services Report Changes 60

61 Regulation, Synchronized Reserve, & Non-Synchronized Reserve Changes FERC Order 825: Settle ancillary service transactions in real-time markets at same interval it prices ancillary services Current Implementation PJM prices Regulation, Synchronized Reserve, and Non-Synchronized Reserve markets on a 5-minute basis PJM settles Regulation, Synchronized Reserve, and Non-Synchronized Reserves markets on hourly basis Settlement Implementation PJM prices and settles Regulation, Synchronized Reserve, and Non-Synchronized Reserve credits on a 5-minute basis Revenue Data for Settlements (energy quantities used in accounting and billing) is used for Regulation, Synchronized Reserve, and Non-Synchronized Reserve credits and charges 61

62 Ancillary Service Market Credit Change Highlights Market-Clearing Price (MCP) and MCP credit is determined for each Real-time Settlement Interval (5-minute interval) Regulation Market Synchronized Reserve Market Non-Synchronized Reserve Market Unit-specific lost operating cost (LOC) and LOC credit are calculated for each 5-minute interval Shoulder Hour LOC calculation uses last three real-time settlement intervals of preceding shoulder hour and first three real-time settlement intervals of following shoulder hour Synchronized Energy Premium is $50/MWh adder 62

63 Ancillary Service Market Charge Change Highlights Hourly obligation remains the same Real-Time Load Ratio Share * Total Supplied (adjusted for any bilaterals) Hourly bilaterals remain the same Hourly adjustment to obligation between buyer and seller Hourly purchases remain the same Hourly-adjusted obligation adjusted by self-scheduled purchases Hourly LOC charge remains the same Total LOC Credits * Net Purchases Total PJM Purchases Methodology change Buyers are charged obligation ratio share of total MCP credits, plus their percentage share of any provider s unrecovered costs over and above their total MCP credits 63

64 Regulation Charge & Credit Changes

65 Regulation Credit RMPCP Credit Regulation (MW) RMCCP Credit Regulation (MW) Assignment (MW) Actual Performance Score Actual Performance Score Mileage Ratio MCP ($/MWh) 12 RMPCP ($/MWh) 12 RMCCP ($/MWh) 12 Regulation Credit For Regulation Market Performance Clearing Price (RMPCP) Credit Assignment is 5-minute Regulation MW adjusted by actual performance and mileage ratio For Regulation Market Capability Clearing Price (RMCCP) Credit Assignment is 5-minute Regulation adjusted based on actual performance MCP s are RMPCP and RMCCP, respectively Total Regulation Clearing Price Credit is RMCCP Credit + RMPCP Credit If 5-minute performance score < 0.25, credits = $ Regulation and Frequency Response Service Tariff - Attachment K Appendix; Section

66 LOC Components 12 - MCP Credit Regulation LOC Credits Regulation Offer LOC Cost 12 Shoulder Hour LOC - RMCCP RMPCP & Credit Regulation LOC Components includes 5-minute regulation offer, plus 5-minute LOC, plus 5-minute shoulder LOC MCP Credit includes 5-minute RMPCP and RMCCP Credits Shoulder hour LOC from ramp-in intervals applied to first 5-minute interval of regulating hour Shoulder hour LOC from ramp-out intervals applied to last 5-minute interval of regulating hour If resulting amount is negative, credit is $ Regulation and Frequency Response Service Tariff - Attachment K Appendix; Section

67 Shoulder Hour Lost Opportunity Cost Ramp-In SH LOC Ramp-Out SH LOC Existing Settlement SH LOC is cost incurred or revenues lost in ramp-in and ramp-out hour to move uneconomically to regulation assignment Determined using hourly LMP and MW values then adjusted by percentage of hour that unit is increased or decreased from its economically desired output using offer ramp rates SH LOC uses hourly integrated values then adjusts using % of hour Ramp-In SH LOC Regulating Hour SH LOC is cost incurred or revenues lost in the 3 ramp-in and ramp-out 5-minute intervals to move uneconomically to regulation assignment Determined using 5-minute LMP and 5-minute MW Regulation high and low limits and Regulation assigned MW from first or last 5-minute interval of regulating hour Ramp-in Shoulder Hour: LOC calculated for last three 5-minute intervals Regulating Hour Ramp-out Shoulder Hour: LOC calculated for first Ramp-In 5-minute three 5-minute intervals Ramp-Out 5- intervals Ramp-Out SH LOC minute intervals SH LOC uses 5-minute values (LMP, EcoMin, EcoMax) LMP EcoMax RegHigh Limit RegLow Limit EcoMin LMP EcoMax RegHigh Limit RegLow Limit EcoMin 67

68 Shoulder Hour Ramp-In Regulation Lost Opportunity Cost Eligibility Current Eligibility Rules Eligibility determined for ramp-in hour Settlements Eligibility Rules Eligibility determined for each 5-minute interval within 15-minute ramp-in period prior to regulating hour On-line during ramp-in shoulder hour Regulation assignment begins at top of hour On-line during all three ramp-in 5-minute intervals No Change Not regulating during ramp-in shoulder hour Not regulating in all three ramp-in 5-minute intervals LMP Desired from prior hour is not already within regulation hour regulation limits LMP Desired from each three ramp-in 5-minute interval is not already within regulation limits of first 5-minute interval of regulation hour 68

69 Shoulder Hour Ramp-Out Regulation Lost Opportunity Cost Eligibility Current Eligibility Rules Settlements Eligibility Rules Eligibility determined for ramp-out hour Eligibility determined for each 5-minute interval within 15-minute ramp-out period after regulating hour On-line during ramp-out shoulder hour On-line in all three ramp-out 5-minute intervals Regulation assignment ends at top of hour No Change Not regulating during ramp-out hour Not regulating in all three ramp-out 5-minute intervals LMP Desired from following hour is not already within regulation hour regulation limits LMP Desired from each three 5-minute ramp-out interval is not already within regulation limits of last 5- minute interval of regulation hour 69

70 Regulation LOC Credit Hydro Resources Current Implementation Settlements Implementation On-Peak and Off- Peak Average LMP LOC (Hydro unit is in spill) LOC Day-Ahead MW > 0 LOC Not Committed Day-Ahead Average RT LMP for all hours during applicable period, excluding hours where all available units at plant are operating Regulation Setpoint biased to reflect reg signal * performance score * benefits factor * real-time LMP (All hourly values) Regulation Setpoint biased to reflect reg signal * performance score * benefits factor * (Hourly RT LMP - Average LMP) Regulation Setpoint biased to reflect reg signal * performance score * benefits factor * (Average LMP - Hourly RT LMP) No Change Regulation Setpoint biased to reflect reg signal * performance score * benefits factor * real-time LMP (All 5- Minute values) Regulation Setpoint biased to reflect reg signal * performance score * benefits factor * ( RT LMP - Average LMP) Regulation Setpoint biased to reflect reg signal * performance score * benefits factor * (Average LMP 5- Minute RT LMP) 70

71 Hourly Adjusted Obligation Hourly Total Adjusted Obligation MCP Credits in Hour RMPCP & RMCCP Regulation Charge Methodology RMPCP Charge Hourly Adjusted Obligation Hourly Total Adjusted Obligation RMPCP Credits in Hour Regulation MCP Credits is RMPCP Credits for Regulation Performance Clearing Price Charge MCP Credits is RMCCP Credits for Regulation Capability Clearing Price Charge RMCCP Charge Hourly Adjusted Obligation Hourly Total Adjusted Obligation RMCCP Credits in Hour 1340 Regulation and Frequency Response Service Tariff - Attachment K Appendix; Section

72 Synchronized Reserve Charge & Credit Changes

73 Synchronized Reserve Credit Assignment (MW) MCP ($/MWh) 12 Tier 1 SR Credit - Non-Shortage Tier 1 SR Credit - Shortage Response (MW) Lesser of Actual Response (MW) OR Estimated Tier 1 Response (MW) 50 ($/MWh) 12 SRMCP ($/MWh) 12 Synchronized Reserve Credit During non-shortage or when NSRMCP is zero Tier 1 Credit = Response * $50/MWh During shortage or when NSRMCP is non-zero, "Assignment for Tier 1 Credit is lesser of 5- Minute Actual Response (MW) OR Estimated Tier 1 Response (MW) MCP is SRMCP 2360 Synchronized Reserve Tariff - Attachment K Appendix; Section 3.2.3A 73

74 Synchronized Reserve Credit (continued) Assignment (MW) MCP ($/MWh) 12 Tier 2 SR Credit SR Assignment (MW) SR Shortfall (MW) SRMCP ($/MWh) 12 Synchronized Reserve Credit For Tier 2 Credit, Assignment is Assigned MW Shortfall MCP is SRMCP If resulting amount is negative, credit is $ Synchronized Reserve Tariff - Attachment K Appendix; Section 3.2.3A 74

75 LOC Components 12 - MCP Credit Synchronized Reserve LOC Credits SR Offer 12 LOC - SRMCP Credit Synchronized Reserve LOC Components "includes SR offer, plus LOC Energy Use is only used for Condensing Unit MCP Credits is SRMCP Credit If resulting amount is negative, credit is $0 (Energy Use * Real-time LMP) + (MW Deviation * ( Real-Time LMP Offer Price)) 2360 Synchronized Reserve Tariff - Attachment K Appendix; Section 3.2.3A 75

76 Synchronized Reserve LOC Credit Hydro Resources Current Implementation Settlements Implementation On-Peak and Off-Peak Average LMP LOC (Hydro unit is in spill) LOC Day-Ahead MW > 0 Average RT LMP for all hours during applicable period, excluding hours where all available units at plant are operating Synchronized Reserve Assigned MW * Hourly Real-Time LMP Synchronized Reserve Assigned MW* (Hourly Real-Time LMP - Average LMP) No Change Synchronized Reserve Assigned MW * 5- Minute Real-Time LMP Synchronized Reserve Assigned MW * ( Real-Time LMP - Average LMP) If average LMP value is higher than 5- minute Real-Time LMP at generator bus, LOC is zero LOC Not Committed Day-Ahead LOC = 0 No Change 76

77 Hourly Adjusted Obligation Hourly Total Adjusted Obligation MCP Credits in Hour Synchronized Reserve Charge Methodology Tier 1 Charge Tier 2 Charge Hourly Tier 1 Obligation Hourly Total Tier 1 Obligation Hourly Tier 2 Obligation Hourly Total Tier 2 Obligation Tier 1 Credits in Hour SRMCP Tier 2 Credits in Hour Synchronized Reserve MCP Credits is SRMCP Tier 1 or Tier 2 Credits If hourly integrated SRMCP is equal for all sub-zones within reserve zone, Total Tier 2 Credits are allocated based on Market participants above obligation ratio share in reserve zone If the hourly-integrated SRMCP is different for sub-zones within reserve zone, Total Tier 2 Credits in sub-zone are allocated based on Market Participant s above obligation ratio share in the subzone 1360 Synchronized Reserve Tariff - Attachment K Appendix; Section 3.2.3A 77

78 Tier 2 Retroactive Penalty Charge Resource Shortfall MW Synchronized Reserve Tariff - Attachment K Appendix; Section 3.2.3A Resource Shortfall MW Participant s Total Shortfall MW Resource Retroactive Shortfall MW Participant s Total Over Response MW SRMCP 12 Tier 2 Retroactive Penalty Charge Applies to Tier 2 resources only Calculation performed for all 5-minute assignments going back to lessor of last event during which resource is penalized OR average number of days between events If there are multiple Synchronized Reserve Events during day, maximum Resource Retroactive Shortfall MW for day is used to determine what Market Participant owes in refund charges If resulting amount is less than 0 MW, Retroactive Shortfall MW is equal to 0 MW 78

79 Non-Synchronized Reserve Charge & Credit Changes

80 Assignment (MW) MCP ($/MWh) 12 Non-Synchronized Reserve Credit NSR Assignment (MW) NSR Shortfall (MW) NSRMCP ($/MWh) 12 Non-Synchronized Reserve Credit Assignment is adjusted by shortfall MCP is NSRMCP 2362 Non-Synchronized Reserve Tariff - Attachment K Appendix; Section 3.2.3A

81 LOC Components 12 - MCP Credit Non-Synchronized Reserve LOC Credits LMP Desired MW RT LMP 12 - Offer at LMP Desired 12 - NSRMCP Credit Non-Synchronized Reserve LOC Components include LMP Desired MW times the 5-minute LMP, less the Offer at desired LMP MCP Credit is NSRMCP Credit If resulting amount is negative, credit is $ Non-Synchronized Reserve Tariff - Attachment K Appendix; Section 3.2.3A

82 NSR LOC Credit Hydro Resources Current Hourly Implementation Settlements Implementation On-Peak and Off-Peak Average LMP LOC Day-Ahead MW > 0 LOC Not Committed Day- Ahead Average RT LMP at hydro bus for all hours during the applicable period, excluding hours where all available units at the plant are operating Non-Sync Assigned MW * (Realtime LMP - Average Real-time LMP) LOC = 0 No Change Non-Sync Assigned MW * ( Real- Time LMP - Average Real-Time LMP) If average Real-Time LMP value is higher than Real- Time 5-minute LMP at generator bus, LOC is zero No Change 82

83 Hourly Adjusted Obligation Hourly Total Adjusted Obligation MCP Credits in Hour Hourly Adjusted Obligation 5- Minute Hourly Total Adjusted Obligation NSRMCP Credits in Hour Non-Synchronized Reserve Charge Methodology Non-Synchronized Reserve MCP Credits is NSRMCP Credits If hourly-integrated NSRMCP is different for sub-zones within reserve zone, Total Non-Synchronized Reserve Clearing Price Credits in sub-zone are allocated based on Market Participant s above obligation ratio share in sub-zone If hourly integrated NSRMCP is equal for all sub-zones within reserve zone, Total Non-Synchronized Reserve Clearing Price Credits are allocated based on Market participants above obligation ratio share in reserve zone 1362 Non-Synchronized Reserve Tariff - Attachment K Appendix; Section 3.2.3A

84 Ancillary Service Report Changes

85 Regulation Settlements Report Changes Report Regulation Credits Load Response Regulation Credits Regulation Summary Preliminary Regulation Summary Changes Change to exist report to present data on a 5-minute interval basis. All existing data fields on the report remain. New data fields added to support Hydro LOC calculations. Change to exist report to present data on a 5-minute interval basis. All existing data fields on the report remain. Change to existing report format that removes regulation market clearing prices and adds total amounts of RMCCP and RMPCP credits for charge allocation. Change to existing report format that adds new data fields for Total RMCCP credits and Total RMPCP credits. RMPCP and RMCCP are hourly integrated clearing prices. 85

86 Synchronized Reserve Settlements Report Changes Report Synchronized Reserve Credit Summary Synchronized Reserve Tier 1 Credits Synchronized Reserve Tier 2 Credits Preliminary Synchronized Reserve Summary Synchronized Reserve Tier 2 Charge Summary Synchronized Reserve Tier 2 Retroactive Penalty Charges Changes Change to existing report format to report data on a 5-minute basis. All existing data fields on the report remain the same. Change to existing report format to report data on a 5-minute basis. All existing data fields on the report remain the same. Change to existing report format to report data on a 5-minute basis. All existing data fields on the report remain the same. Change to existing report format to remove SRMCP value and add hourly total for Tier 2 Credits. Change to existing report format to remove SRMCP value and add hourly total for Tier 2 Credits. Change to existing report format to report data on a 5-minute basis. All existing data fields on the report remain the same. 86

87 Non-Synchronized Reserve Settlements Report Changes Report Non-Synchronized Reserve Credits Non-Synchronized Reserve Summary Preliminary Non-Synchronized Reserve Summary Settlement Implementation Changes Change to existing report format to present data on 5 minute interval basis. Added new columns LMP Desired MW, RT LMP, and Offer at LMP Desired fields. Change to existing report format to remove NSRMCP; NSRMCP Credits are the sum of credits from a sub-hourly basis. New columns Total PJM Reserve Zone Non-Synch Reserve Obligation and Total PJM Reserve Zone NSRMCP Credits are added. Change to existing report format to display NSRMCP value as hourly integrated value and includes hourly total for NSRMCP Credit. Settlements Reports 87

88 Uplift Credits & Charges

89 Discussion Topics Uplift Highlights Balancing Operating Reserve & Reactive Services Credit Changes Lost Opportunity Cost Credit Changes Synchronous Condensing Credit Changes Balancing Operating Reserve Charge Changes Report Changes 89

90 Day-ahead Operating Reserve Credit and Charges No change Balancing Operating Reserve Credits Offer and Revenues calculated for each 5-minute interval Operating Reserve Change Highlights Segments continue to be determined for operating periods but are no longer limited to hour boundary, can start and stop within an hour Balancing Operating Reserve Charges No change to Balancing Operating Reserve Cost Allocation methodology: Reliability or Deviations Regional allocation of Balancing Operating Reserve charges remains daily Deviations determined for each 5-minute interval 90

91 Lost Opportunity Cost Change Highlights Lost Opportunity Cost Credit - Evaluated for each 5-minute interval - Flexible unit LOC when scheduled Day-ahead and not called on in Real-time no longer limited to entire hour Evaluated for each 5-minute interval not operating in Real-time Lost Opportunity Cost Charges - No change - Included in total RTO Balancing Operating Reserve Credits and allocated to deviations 91

92 Reactive Services Change Highlights Reactive Services Credits If resource output is increased Offer and Revenues calculated for each 5-minute interval Segments continue to be determined for operating periods, but are no longer limited to hour boundary, can start and stop within an hour If resource output is decreased LOC credit for each 5-minute interval Reactive Service Charges No change Allocated daily to zonal load 92

93 Other Change Highlights Condensing Credit (for purposes other than providing Reactive Services or Synchronized Reserve) Condensing Cost calculated for each 5-minute interval Lost Opportunity Cost calculated for each 5-minute interval Condensing Charge No change Allocated daily to RTO load and exports Cancellation Credit and Charge No change Credit: Daily capped at startup cost - Charges: Included in total RTO Balancing Operating Reserve Credits and allocated to deviations 93

94 Balancing Operating Reserve & Reactive Services Credits 94

95 Make Whole Credit Balancing Operating Reserves & Reactive Services Review Purpose is to cover costs represented in resource offers Results in prices and compensation that preserves incentive for generation and Demand Resources to follow real-time dispatch signals/instructions Total resource offer amount, including startup and no-load costs as applicable, is compared to its total energy market value and ancillary service value for specified operating period segments during day If total value is less than offer amount, difference is credited to the PJM Member If unit is increased to provide Reactive Services, same calculations apply Tariff - Attachment K Appendix; Section & 3.2.3B 2375 Balancing Operating Reserve Credits 2378 Reactive Services Credits 95

96 Segmented Make-Whole Credit Resource is made whole for up to two segments for each synchronized start Segment 1: Greater of the Day-Ahead commitment and Min Run time at time of commitment Segment 2: Five-minute intervals in excess of Segment 1 With 5-minute settlements, segments can start/stop during intervals within an hour Segment does not carry over to next day (No change) Start-up costs in Segment 1 (No change) 96 05/24/2017

97 Unit called on and on-line at 7:30 MIN RUN TIME 4 HOURS (7:30 11:30) REAL TIME DISPATCH (11:30 13:30) (beyond min run) Segmented Balancing Operating Reserve Credits Unit Extended Beyond Min Run Time Current Settlements Eligibility and segments assigned for block of hours Hourly integrated MW and prices Settlements Eligibility and segments assigned for 5-minute intervals 5-minute interval MW and prices 4 hours 2 hours 4 hours 2 hours TIME (hour ending) 7:30 11:30 13:30 TIME (5-minute interval begin time) 97 05/24/2017

98 Balancing Operating Reserve Credit Inputs Existing Calculation 5-minute Settlement Calculation Real-time Energy Offer Real-time Start-up Cost No-Load Cost Balancing Value Sync/Non-Sync/ Reactive Revenue DASR Revenue Hourly calculation using applicable offer and hourly MW If hourly MW is greater than 110% of hourly Desired MW, Desired MW is used Applicable startup $ applied to first segment Hourly no-load costs prorated in an hour in which a unit starts or stops generating using a 10% tolerance Value calculated for each hour using applicable hourly integrated MW and LMP values Hourly revenue in excess of offer plus opportunity cost Hourly revenue in excess of offer plus opportunity cost 5-minute calculation using applicable offer and 5-minute Revenue Data for Settlements MW If 5-minute MW is greater than 110% of 5-minute Desired MW, 5-minute Desired MW is used No Change Hourly No-Load cost applied in 5-minute interval, no hourly proration necessary Value calculated for each 5-minute interval, using applicable 5-minute MW and 5-minute Real-time LMP 5-minute revenue in excess of offer plus opportunity cost 5-minute interval share of Hourly revenue in excess of offer plus opportunity cost 98

99 Balancing Operating Reserve Credit Calculation Balancing Operating Reserve Credit for each segment If result is negative, credit is $0 (Real-Time MW Day- Ahead MW) * (Realtime LMP / 12) Real-Time MW is Greater of Real-Time MW Lessor of DA Scheduled MW Greater of RT Dispatch Desired MW Committed Offer Desired MW ( Real- Time Energy Offer including No-Load) + Startup ( Balancing Value) Synchronized & Non Synchronized Reserves, Reactive & DASR Excess Revenues Daily Day- Ahead Value Daily Day-Ahead Operating Reserve Credit All inputs with exception of Startup Cost are sum of 5-minute interval results applicable to segment Startup Cost is applied to applicable segment Only applies to segment corresponding to Day-Ahead Commitment (Segment 1 in Settlements) 99

100 OLD Balancing Operating Reserve Credits Interval Calculations Offer: 100 NEW RT Energy Offer + RT No Load + RT Startup Cost Ancillary Service Offsetting Revenues DASR Offsetting Revenues Balancing Value Sum (RT Energy Offer) + Sum (RT No Load) + RT Startup Cost Sum (Ancillary Service Offsetting Revenues) Sum (DASR Offsetting Revenue)s Sum (Balancing Value) 100

101 Lost Opportunity Cost Credits 101

102 Review of Lost Opportunity Cost Credits Generators whose output is reduced or suspended for reliability may be eligible for Lost Opportunity Cost (LOC) credit Flexible Resources are also eligible for LOC credit if committed Day-Ahead but not operating in Real-Time per PJM dispatch instructions Both components are now being calculated for 5-minute intervals If unit is decreased to provide Reactive Services, same calculations apply 102

103 LOC Credits LOC Credits are calculated for each eligible 5-minute interval If result is negative, credit is $0 LOC Deviation MW Real- Time LMP Desired (MW) Revenue Data for Settlements (MW) Real-Time LMP ($/MWh) 12 Lost Opportunity Cost Offer 12 LMP Desired MW Determined using schedule on which unit is dispatched and 5-minute LMP Adjusted for effective 5-minute Regulation and Synchronized Reserve Assignments Capped at 5-minute economic max or Maximum Facility Output (MFO) Capped at 5-minute wind forecast for wind generators LOC Offer Does not include no-load and startup cost Offer is additional cost unit would have incurred if operating at LMP Desired MW ($/Deviation MW amount) 2375 Balancing Operating Reserve Credits 2378 Reactive Service Credits Tariff - Attachment K Appendix; Section & 3.2.3B 103

104 Flexible Resource LOC Credit Committed Day Ahead Not Operating in Real-Time Each 5-minute interval LOC Credit is higher of Real-Time LMP ($/MWh) 12 Real-Time LMP ($/MWh) 12 Day-Ahead LMP ($/MWh) 12 OR LOC Offer 12 Tariff - Attachment K Appendix; Section & 3.2.3B Day-Ahead Committed MWh Day-Ahead Committed MWh LOC Offer 5-minute offer includes no-load and startup cost Startup cost excluded if resource operates in Real-Time in a 5- minute interval that coincides with Day-Ahead commitment Offer is additional cost unit would have incurred if operating at DA MW ($/DA MW amount) If result is negative, credit is $ Balancing Operating Reserve Credits 2378 Reactive Service Credits 104

105 Synchronous Condensing Credits 105

106 Synchronous Condensing Credits Credits for synchronous condensing for purposes other than Synchronized Reserves or Reactive Services calculated for each 5-minute interval If condensing for Reactive Services, credit is the the greater of the 5-minute SRMCP / 12 * Economic Max OR the Condensing and LOC credits below Condensing Credit Duration for 5- Minute interval Hourly Cost to Condense ($) 12 Energy Use Cost 12 Applicable Startup Cost Condensing LOC Credit LMP Desired (MW) Actual Output (MW) LMP ($/MWh) 12 Lost Opportunity Cost Offer 12 Tariff - Attachment K Appendix; Section Synchronous Condensing Credits 106

107 Uplift Charges 107

108 Charge Overview Credit Category (BLI) Allocation Interval Allocation Level Charges Paid by Charge Category (BLI) 5-minute Settlements Impact Day-ahead Operating Reserve Credit (2370) Daily RTO Day-ahead Load Day-ahead Decrement Transactions Day-ahead Exports Day-ahead Operating Reserve Charge (1370) No Change Day-ahead Operating Reserve for Load Response Credits (2371) Daily RTO Day-ahead Load Day-ahead Decrement Transactions Day-ahead Exports Day-ahead Operating Reserve for Load Response Charges (1371) No Change Balancing Operating Reserve Credits for Reliability (2375) Daily RTO East Region West Region Real-time Load Real-time Exports Balancing Operating Reserve Charges for Reliability (1375) No Change Balancing Operating Reserve Credits for Deviations (2375) Daily RTO East Region West Region Withdrawal Deviations Injection Deviations Generator Deviations Balancing Operating Reserve Charges for Deviations (1375) Deviations calculated for each 5-minute interval Balancing Operating Reserve for Load Response Credits (2376) Daily RTO Withdrawal Deviations Injection Deviations Generator Deviations Balancing Operating Reserve for Load Response Charges (1376) Deviations calculated for each 5-minute interval 108

109 Charge Overview Credit Category (BLI) Allocation Interval Allocation Level Charges Paid By Charge Category (BLI) Settlements Impact Reactive Service Credits (2378) Daily Zonal Real-time Load Reactive Services Charges (1378) No Change Synchronous Condensing Credits (2377) Daily RTO Real-time Load Real-time Exports Synchronous Condensing Charges (1377) No Change 109

110 Deviation Calculation Buckets Balancing Operating Reserve Charges for Deviations Applied to Day-Ahead Cleared Decrements, DA Load, Sales/Export By Zone, by Hub, by Interface Cleared Increments, Purchases/Imports By Zone, by Hub, by Interface DA Scheduled Generation or Desired MW Withdrawal Deviations Net Deviation of total Injection Deviations Net Deviation of total Generator Deviations Individual deviation on each generator not following dispatch Real-Time RT Load, Sales/Export By Zone, by Hub, by Interface Purchases/Imports By Zone, by Hub, by Interface RT Generation 110

111 Operating Reserve Withdrawal Deviation Example NEW OLD Hourly average of 5- minute intervals 111

112 NEW Operating Reserve Injection Deviation Example OLD Hourly average of 5- minute intervals 112

113 Generator Deviations Interval 1. Assess generator eligibility for deviations using current business rules 2. If eligible, calculate generator deviation MW 3. If generator deviation MW ratio is within 5%, no deviations calculated 4. Apply supplier netting for units located at single bus Hour 1. Average of 5-minute generator deviation MW 2. If average generator deviation < 5 MWh, no deviations calculated Day 1. Total Generator Hourly Deviations 113

114 Operating Reserve Generator Deviation Example NEW OLD Hourly average of 5- minute intervals 114

115 New Operating Reserve Reports Report Balancing Operating Reserve Generator Credit Details Operating Reserve Deviation Summary - 5 min Operating Reserve Generator Deviations - 5 min Changes New report that displays all supporting balancing generator credit data details on a sub-hourly basis. New report to display generator deviations, injection deviations, and withdrawal deviations by location on a sub-hourly basis. New report to display generator deviation values on a sub-hourly basis. 115

116 MSRS Operating Reserve Report Changes Report Day-Ahead Operating Reserve Generator Credit Details CT Lost Opportunity Cost Forfeiture Operating Reserve Lost Opportunity Cost Credits Operating Reserve Lost Opportunity Cost for Pump Hydro Credits Reactive Services Credits Changes Change to exist Operating Reserve Generator Credit Details report format and data elements. Report only displays Day-ahead values and continues to report on an hourly level. Change to existing report format to display data on a 5-minute interval basis. All existing data fields on the report remain. Change to existing report format to display data on a 5-minute interval basis. All existing data fields on the report remain. Change to existing report format to display data on a 5-minute interval basis. All existing data fields on the report remain. Change to existing report format to display data on a 5-minute interval basis. All existing data fields on the report remain. 116

117 Terminated Reports Report Operating Reserve Generator Credit Details Changes Report format terminates 4/1/2018. Operating Reserve Generator Credit Details is reported in Day-Ahead Operating Reserve Generator Credit details, which keeps the same format as the existing report, and in Balancing Operating Reserve Generator Credit details which reports data on a 5-minute level. Settlements Reports 117

118 Load Response

119 Discussion Topics Load Response Change Highlights Full Emergency, Emergency Energy Only, and Real-Time Economic Load Response Credit Changes Net Benefits Test for Economic Load Response Changes 119

120 Load Response Change Highlights Day-ahead Economic Load Response Credits No change Full Emergency, Emergency Energy Only, and Real-time Economic Load Response Credits Calculated for each 5-minute interval Actual MWh relief is distributed over all 5-minute intervals dispatched by PJM Each 5-minute response MW is capped at the Customer Base Line (CBL) Net Benefits Test for Economic Load Response Applies to each 5-minute interval of curtailment 120

121 Load Response Credit Calculation CBL Real-Time Metered Load Net Energy MWh Actual MWh Relief Provided (1 EDC Loss De- Ration Factor) Energy Loss Factor Cleared Day- Ahead MWh Load Only applies to RT Economic Load Response Capped at CBL Evenly distributed over all 5-minute intervals in hour registration is dispatched Real-Time Load Response Distributed MW Net Energy MWh 12 Number of Intervals in Hour Registration is Dispatched 121

122 Full Emergency & Emergency Energy Only Credit Calculation Full Emergency or Emergency Energy Only Credit Real-Time Load Response Distributed MW Appropriate Real-Time Zonal or Agg LMP Emergency Load Response Tariff - Attachment K Appendix; Section

123 Real-time Economic Load Response Credit If Net Benefit Threshold Real-Time LMP, then Real-Time Economic Load Response Credit Real-Time Load Response Distributed MW Appropriate Real-Time Zonal or Agg LMP 12 If Net Benefit Threshold > Real-Time LMP, then Real-Time Economic Load Response Credit $ Real-Time Economic Load Response Tariff - Attachment K Appendix; Section 3.3A.5 123

124 Net Benefits Test Net Benefits Threshold No change Price, calculated monthly, represents price point at which economic demand reduction is considered to be of benefit Net Benefits Test Comparison of applicable real-time locational marginal price vs. Net Benefits Threshold on five-minute basis 124

125 Real-Time Economic Load Response Settlement Example (CBL RT Metered Load) * ( 1 EDC Loss De-Ration Factor) * Energy Loss Factor Customer Baseline 9.0 Real-time Metered Load EDC Loss De-Ration Factor Energy Loss Factor Net Energy MWh 7.75 Net Benefits Threshold $ Net Energy MWh * (12 / Number of Intervals Dispatched) OLD Hour Ending Net Energy (MWh) LMP ($/MWh) Hourly Settlement (Net Energy * LMP) $24.67 $ NEW Real-time Dispatched Load Net Applying Response LMP Benefits CBL Cap Distributed ($/MWh) Threshold MW : $ $ Interval Begin Time : $ $ Realtime Economic Load Response Credit : $ $ $ : $ $ $ : $ $ : $ $ : $ $ : $ $ $ : $ $ $ : $ $ : $ $ $ : $ $ $ Total $

126 Load Response Operating Reserve Credits OLD Net Energy MWh * Bid Price Hour Net Energy LMP Hourly Credit Shutdown Op Res Ending (MWh) ($/MWh) (Net Energy * LMP) Cost DR Bid Credit $24.67 $ $ $ $ Bid Price $25.00 Distributed MW Capped at CBL 9 DR Bid + Shutdown Cost Hourly Credit NEW (Bid Price / 12) * Distributed MW Interval Begin Time Dispatched :00 0 :05 0 Real-time Economic Load Response Credit DR Bid + Shutdown Cost 5 Min Credit Shutdown Cost Demand Response Bid Op Res Credit :10 1 $ $ $ $ :15 1 $ $ $ 0.75 :20 1 $ $ :25 1 $ $ :30 1 $ $ :35 1 $ $ $ - :40 1 $ $ $ - :45 1 $ $ :50 1 $ $ $ 0.75 :55 1 $ $ $ - Total $

127 Load Response Settlements Report Changes Report Load Response Tier 1 Credits Load Response Tier 2 Credits Load Response Summary Emergency Load Response Allocation Summary Real-time Load Response Credits Settlement Implementation Changes Change to existing report format to present data on 5-minute interval basis. Change to existing report format to present data on 5-minute interval basis. New report format removes Real-Time pricing from the report and report Real-time Credits as hourly summations from a 5-minute sub-hourly level reported on the Real-time Load Response Credits report. Data remains hourly. New report format breaks interchange columns into columns for Injections and Withdrawals. Report remains hourly. New report to display Real-time Economic Load Response Credits on a sub-hourly basis. Report includes Real-time Economic Load Response Credits, Emergency Load Response Credits, and Emergency Load Response Make-Whole Credits. Settlements Reports 127

128 Capacity Performance 128

129 Capacity Performance Change Highlights Non-Performance Assessment Transitions from Performance Assessment Hour to Performance Assessment Interval Performance Assessment Interval is each Real-Time Settlement Interval for which an Emergency Action has been declared by PJM Emergency Action Triggers No change Non-Performance Charges & Bonus Performance Credits Calculated for each Performance Assessment Interval 129

130 Performance Assessment Interval Triggers (Steps 1-10 in Sections 2 and 5 of Emergency Procedures Manual 13) Pre-Emergency Load Management Reduction Action (30, 60 or 120 minute) Emergency Load Management Reduction Action (30, 60 or 120 minute) Primary Reserve Warning Maximum Generation Emergency Emergency Voluntary Energy Only Demand Response Reductions Voltage Reduction Warning Curtailment of Non-Essential Building Load Deploy All Resources Action Manual Load Dump Warning Voltage Reduction Action Manual Load Dump Action Warnings Actions (Section 5.7 of Emergency Procedures Manual 13) Load Shed Directive 130

131 Balancing Ratio (BR) Used to calculate Capacity/Base Performance resource's Expected Performance value Calculated for each Performance Assessment Interval (PAI) of Emergency event Total Actual Generation & Storage Performance + Net Energy Imports + Demand Response Bonus Performance All Generation & Storage Committed UCAP 131

132 Non-Performance Assessment Assess performance of resources during PAI triggered by PJM declaration of Emergency Actions Compare each resource s Expected Performance against Actual Performance for each PAI Calculate shortfall/excess for each resource for each PAI separately 132

133 Non-Performance Assessment for Generation UCAP * Balancing Ratio Generation Resource Revenue Data for Settlements OLD Hour Ending UCAP * Balancing Ratio UCAP (MWh) Balancing Ratio Expected Performance (MWh) Actual Performance (MWh) Shortfall (MWh) NEW Bonus (MWh) Interval Begin Time UCAP (MW) Balancing Ratio Expected Performance (MW) Actual Performance (MW) Shortfall (MW) Bonus (MW) : : : : : : : : : : : :

134 Non-Performance Assessment for Demand Resources Hourly Load Reduction 7.75 Peak Load Contribution 9.00 Winter Peak Load 8.80 ICAP MW Commitment 8.90 OLD Hour Ending % Hour Dispatched ICAP * % Hour Dispatched Load Reduction (MWh) ICAP (MWh) Expected Performance (MWh) Shortfall (MWh) Bonus (MWh) % NEW ICAP MW Commitment Interval Begin Time Dispatched Expected Performance (MW) Interval Load Reduction (MW) Hourly Load Reduction * (12 / Number of Intervals Dispatched) PLC Capped Interval Load Reduction (MW) Shortfall (MW) Bonus (MW) : : : : : : : : : : : :

135 Non-Performance Charge for a PAI If Expected Performance is > Actual Performance, then resource has Performance Shortfall and may be subject to Non-Performance Charges Non- Performance Charge Performance Shortfall MW Non- Performance Charge Rate (NPCR) NPCR for Capacity Performance Resources Based on Net CONE of modeled LDA in which resource resides Rate = ( (Net CONE * 365 days) / 30 Hours) / Number of Real-Time Settlement Intervals in Hour NPCR for Base Capacity Resources Based on weightedaverage clearing price applicable to resource Rate = ( (WARCP * 365 days) / 30 Hours) / Number of Real-Time Settlement Intervals in Hour 135