2. 2.1. PJMERCOT EU EUNord Pool 2.1.1. (1) 1995 1999 2003 3 1995 4 1997 7 20kV 2,000kW 1999 5 3 2,000kW 7,000V 4 1 3 1 0.4 2-1
2001 11 2003 2005 4 4 2005 4 2.1.1-1 2.1.1-1 2005 4 1 2003 2007 2-2
2.1.1-2 2,000kW 20kV 500kW 50kW 6kV (6.6kV) 100 200V 0.9 26% 2 27 9% 9% 2 43 5% 14% 640 5% 7,000 31% 2004.4 2005.4 2007.4 2007 13 2001 1996 2002 5 740 kw IPP 2001 3 160 kw IPP 2004 3 PPS 10 PPS 2 3 5 kwh 2.1.1-3 2.1.1-3 2-3
(2) 2003 18 1 2 2005 4 1 NETA EEX 2.1.1-1 2003 2 18 1 2.1.1-1 1 1 1 kwh 2-4
2.1.2. 2.1.2.1. (1) 1) 1978 PURPA PURPA NUG NUG PURPA NUG 1992 EPAct IPP PUHCA EWG EPAct EWG IPP EPAct EWG FERC 1996 FERC 888/889 OASIS 888/889 PJM ISO FERC 1996 5 888 1999 RTO 2000 FERC 4 1 ISO FERC 888/889 2000 2-5
2002 7 SMD NOPR SMD FERC 2001 1999 FERC 2002 NOPR 2004 9 SMD 1,000 FERC 2003 4 Wholesale Power Market Platform Midwest ISO PJM 2000 RTO FERC 2003 9 RTO RTO SMD 2) FERC (a) FERC 2000 RTO RTO RTO 2-6
seams (b) SMD FERC SMD 4 1 2 3 4 a) FERC SMD SMD demand response SMD b) FERC 3 LMP 2-7
c) FERC LMP market manipulation ITP MMU FERC OMOI SMD d) SMD resource adequacy requirement (c) SMD FERC SMD ITP (b) 1 1 4 LMP CRR 4 3 4 2 3 a) ISO RTO ITC 1 ITP b) FERC pro forma Network Integration Service Point-to-Point Transmission Service 2-8
1 Network Access Service c) LMP CRR SMD LMP LMP PJM ISO 2 1 ITP 2-9
2.1.2-1 LMP 1) A1 100MW 3.5 /kwh A2 100MW 2 /kwh LA 25MW C1 25MW =350MW LC 5MW A =90MW C =80MW =200MW =50MW =90MW D B =100MW D2 B1 D1 50MW 90MW LB 100MW 5 /kwh 3.25 /kwh 5MW LD1 LD2 3 /kwh 25MW 290MW C1 25MW@0 /kwh A2 100MW@2 /kwh D1 100MW@3 /kwh B1 90MW@3.25 /kwh LMP A1 35MW@3.5 /kwh 3.5 /kwh 350MW 2) LMP LMP = 3.75 /kwh A2 =350MW C1 A1 100MW LA 25MW 100MW 2 /kwh LC 25MW 3.5 /kwh 5MW 35MW 100MW 25MW A =90MW C LMP = 3.5 /kwh 60MW =0MW 10MW 50MW 90MW =50MW =90MW =80MW 100MW D B =100MW D2 65MW 100MW 25MW B1 50MW D1 90MW LB 5 /kwh 100MW 3.25 /kwh 5MW 3 /kwh LMP LMP = 3.25 /kwh = 5 /kwh ITP LMP 1 ITP LMP Energy LMP 2-10
hub Hub Price Zone Price LMP LMP MCC Marginal Congestion cost ComponentMLC Marginal Losses Component Energy LMP EnergyLMP = SMP + MCC + MLC i r i SMP r r MCCi r i MLC r i i MCC MCC i = ( K k= 1 GSF FMP ) ik k i k ri 2 ID GSF ik i 1MW r 1MW k FMP k LMP k 1MW MLC MLC = ( DF 1) SMP i i r DF i i delivery factor DFi = ( 1 L / Gi ) L i G i Hub Pr ice L / G i i 1MW j = n i= 1 ( W Hi LMP ) n Hub j i WHi ITP Zone Pr ice j = n i= 1 ( W Zi LMP ) n Zone j WZi i 2 2 2-11
SMD CRR CRR PJM 2.1.2-2 CRR A LMP = $30/MWh LMP = $40/MWh B CRR = 100MW = 100MWh C LMP = $60/MWh A CCRR100 [MW]60 30 [$/MWh] $3,000 B C100 [MWh]60-40 [$/MWh] $2,000 CRR$1,000 CRR CRR CRR Receipt Point-to-Delivery Point Congestion Revenue Rights 2 Obligation Rights CRR Option Rights CRR Flowgate Congestion Revenue Rights 2-12
SMD CRR 2 d) LSE 12% one-day-in-ten-years 10 24 18% ICAP PJM ISO ICAP ICAP ICAP ICAP ICAP ICAP SMD ITP LSE LSE LSE e) SMD SMD must offer obligation localized market power 2-13
safety-net bid cap $1,000/MWh 3 FERC OMOISMD ITP MMU MMU PJM ISO ISO New England ISO Midwest ISO FERC OMOI MMU 2.1.2-1 2-14
2.1.2-1 FERC OMOI FERC FERC MMU Load Pocket 3 2.1.2-7 FERC ITP - - - ITP ITP ITP 3 2-15
2.1.2-3 1) Physical Withholding /MWh mark-up MW 2) Economicl Withholding /MWh mark-up MW (d) SMD a) FERC SMD 2-16
SMD ITP FERC LSE b) NERC 25 1 2,000 SMD LMP CRR LMP PJM RTO ISO LMP CRR CRR ITP 3) 1997 1998 1 3 3 3 2004 2 50 D.C. 17 D.C. 2.1.2-4 2000 2001 2-17
2.1.2-4 2004 2 Energy Information Administration RTO NERC 2004 (2) 2.1.2-2 2-18
2.1.2-2 FERC Public Utility Commission Public Service Commission Pennsylvania Public Utility Commission Public Utility Commission of Texas 2.1.2.2. PJM (1) PJM PJM PJM 1927 PJM 2-19
2.1.2-5 PJM PJM RTO WWW (2) PJM PJM 2.1.2-3 2-20
2.1.2-3 PJM 1927 1993 PJM Interconnection Association 7 1 Philadelphia Electric Company PECO Energy Company 1996 FERC ISO PJM 12 31 1997 FERC 2 28 PJM 1998 LMP 1999 FERC PJM FTR 2000 2001 Allegheny Power PJM PJM West 4 1 ISO ISO (3) PJM Electricity Generation Customer Choice & Competition Act HB 1509 1996 12 1997 11 1998 12 5% 25 1999 1 66%2000 1 (4) PJM RTO (5) PJM RTO PJM PJM 2-21
Board of ManagersPJM PJM 7 PJM Interconnection 8 PJM PJM 7 5 PJM 7 4 4 1 1 1 Member Committee PJM PJM PJM RTO PJM PJM 5 Generation Owners Transmission Owners Other Suppliers Electric Distributors End-Use Customers 2.1.2-6 PJM PJM RTO 4 PJM 2-22
2.1.2-6 PJM RTO PJM ISO-LLC Operating Agreement Transmission Owners Administrative Committee) Reliability Committee) Finance Committee) Board of Managers) PJM7 User Group) OI PJM Office of the Interconnection OI PJM Members Committee) OI Tariff Advisory Committee) Audit Advisory Committee) Planning Committee) Operating Committee) Energy Market Committee) PJM Interconnection, Organization Structure 2-23
(6) 1) PJM 2.1.2-4 PJM RTO Self-Schedule PJM RTO 2.1.2-4 PJM PJM Interchange Energy Market Self-Schedule PJM RTO LMP Capacity Resource 5 PJM RTO PJM RTO Capacity Resource PJM PJM Interchange Energy Market PJM 2) PJM RTO Prescheduling Scheduling Dispatch 3 (a) Prescheduling PJM RTO PJM 5 PJM RTO LSECapacity Resource Generator Forced OutagePJM RTOPJM Capacity Resources PJM RTO 2-24
2.1.2-5 PJM RTO 2.1.2-6 2.1.2-5 Prescheduling Planned Outages Generator Maintenance Outages Forced Outages PJM RTOCapacity Resource 6 30 PJM RTO 3 PJM RTO Capacity Resource PJM RTO PJMCapacity Resource PJM RTO 6 PJM RTO LSECapacity Resource PJM RTOPJMCapacity Resources PJM RTO 2-25
2.1.2-6 PJM PJM RTO PJMPJM RTO PJM RTO 30 PJM RTO start-up feesno-load fees PJM 2.1.2-7 0:00 D-30 0:00 D-3 0:00 8:00 12:00 0:00 0:00 D-2 D-1 D D+1 D+2 0:00 D+3 D+4 D+5 0:00 D+6 (b) Scheduling 1 PJM RTO PJM 2-26
PJM 1 PJM 2.1.2-8 0:00 4:00 8:00 12:00 16:00 20:00 22:00 0:00 4:00 8:00 12:00 16:00 20:00 0:00 D-1 D D+1 D+2 D+3 D+4 D+5 D+6 PJM OI ACES Day-Ahead Scheduling 2.1.2-7 PJM RTO PJM RTO 4 7 PJM OASIS 2-27
2.1.2-7 PJM RTO Market Buyer 7 Market Seller Capacity Resource PJM RTO [MW] $/MWh $1000/MWh $/MWh * 1 **Capacity Resource 7Capacity Resource 7 PJM PJM 1999 3 31 PJM PJM RTO 1999 3 10 FERC market-based offers 4 1 3 a) Cost-capped Offers 99 4 1 (Offer for Energy: $/MWh) 10% 1.1 b) LMP LMP-capped Offers 6 8 LMP c) Market-based Offers $1,000/MWh 7 8 2-28
PJM, LMP FERC LMP 2.1.2-8 1,000/MWh 9 1MWh /LMP +10% 0 ID 0 LMP 1 10 2 2.1.2-8 PJM Offer LMP Offer for Energy [$/MWh] Start-up [$/ ] No-load [$/ ] 1MWh 10% 10-10% 10% 6 LMP PJM Interconnection, Market-based Offers Training Workshop 10 - ID 2 ID 2 PJM RTO PJM RTO Real-time Market PJM 9 10 $/ $/ 2-29
16 18 LMP LMP LMP 5 5 1 LMP Hourly Scheduling 10 PJM RTO 60 2.1.2-9 Pool-Scheduled Resources PJM RTO 2.1.2-9 PJM PJM RTO PJM RTO (c) PJM RTO 2 3 1 3 co-optimization LMPLMP State Estimator 2-30
11 LMP (d) PJM RTO forecast PJM Control Area requirement LSE 12 LSEPJM a) PJM PJM LSE PJM Planning & Engineering Committee diversified planning period peak generator unit reliability reserve requirements due to large units PJM PJM the relations between PJM Member and PJM Control Area annual load shapes PJM PJM PJM Control Area reserve margin Planning & Engineering Committee PJM Planning & Engineering Committee Planning & Engineering Committee PJM diversified planning period peak PJM diversified planning period peak 11 contingency 12 Load Serving Entities 2-31
PJM PJM diversified planning period peak 1 (%) /100 b) LSE LSE forecast obligationpjm LSE P 1R F U D /100 (A) P LSE Diversified Planning Period PeakLSE diversified planning period peak R PJM Control Area Reserve MarginPJM F LSE Forced Outage Rate Adjustment LSE Forced Outage Rate: FOR FOR PJM U Large Unit Adjustment 1,300MW D LSE Load Drop AdjustmentLSE PJM LSE load drop LSE 2-32
2.1.2-9 PJM LSE A P, R, F, U, D (A) B C D LSE A LSE B PJM 1 (P), MW 6,283 2,939 47,610 2 PJM, MW 57,370 D1*(1+D3/100) 3 PJM (R), % 20.5% 20.5% 20.5% 4 (F), % 0.6% -0.17% 5 (U), % 0.0% 0.0% 6 (D), % 0.0% 0.0% 7, % 21.1% 20.4% 20.5% A3+A4+A5+A6,D6=D3 8, MW 1,326 599 9,760 A1*A7 9, MW 7,609 3,538 57,370 A1+A8 10, MW 7,708 3,316 57,268 11 PJM, MW 0 12 PJM, MW 0 13, MW 335 264 2,658 14, MW 34 15 Planned System Resource, MW 8,043 3,580 59,960 A10+A11+A12+A13+A14 16 0 0 0 IF D9>D15,THEN(D9-D15)/D15,ELSE=0.0 17, MW 0 0 0 A8*D16 18, MW 7,609 3,538 57,370 A9-A17 19, MW 0 0 0 IF A18>A15,THEN A18-A15,ELSE=0.0 20, MW 434 42 2,590 IF A15>A18,THEN A15-A18,ELSE=0.0 21, MW LSE 0 0 0 (A20/D20)*D19 22, MW forecast obligation 8,043 3,580 59,960 A15+A19-A21 2-33
c) PJM Capacity Credit Market PJM RTO PJM Reliability Assurance Agreement LSE LSE LSE PJM RTO ecapacity dailymonthlymulti-monthly 3 7 10 / PJM Interconnection 0.1MW market clearing price / ecapacity 2.1.2-10 PJM / / // / MW $/MW / estimated obligation 12 unforced capacity 13 / /mandatory bids / PJM Manual M-31 Customer Choice 13 12 2-34
(7) 1) PJM PJM PJM RTEP RTEP PJM RTO RTEP PJM RTO PJM West PJM RTEP Planning Committee Transmission Expansion Advisory Committee 2 ISO RTEP RTEP Transmission Expansion Advisory Committee ISO RTEP PJM Transmission CustomerPJM PJM PJM RTO RTEP 10 RTEP (a) PJM RTO 1 14 14 2-35
ISO (b) PJM RTO PJM (c) PJM PJM RTO 10 interruptible load PJM MW & MVar PJM RTO PJM RTO PJM PJM RTO (d) RTEP PJM RTO RTEP PJM RTO PJM RTO 2-36
RTEP RTEP PJM PJM West RTEP RTEP PJM RTO RTEP (e) RTEP PJM RTO RTEP PJM PJM RTO RTEP RTEP 2.1.2-11 2-37
2.1.2-11 1) 500kV 15 2) 230 345kV 1/2 1/2 1/2 3) 230kV 4) 1 1) 3) 2 1) 3) 2 100kV PJM Interconnection 2) PJM PJM HB 1509 1997 1 1 Cost of Service Performance-Based Regulation 3) "Shopping Credit" 2001 Shopping Credit 4) HB 1509 CTC CTC 15 PJMPJM West 2-38
PUC PJM Duquesne Light Co. GPU 2.1.2.3. ERCOT (1) ERCOT ERCOT NERC 10 Regional Council 1 ERCOT 85% 65,000MW 6,500 kw ERCOT PUCT 2.1.2-10 NERC NERC http://www.nerc.com/ (2) ERCOT 1995 Texas State Legislature PURPA ERCOT 1996 9 11 ERCOT ISO 1999 7 Senate Bill 7 2002 1 1 2002 1 1 2-39
SB7 1) PGC TDSPREP TSDP 1 75,000 100 2) TDSP 1 TDSP 2004 1 3) 2002 1 1 PGC ERCOT 20% 4) Price to Beat REP TDSP 100kW 1999 1 1 6% Price to Beat REP 36 40% REP Price to Beat Public Utility Policy Act PURA 2004 1 TDSP 40% 2005 9 1 TDSP (3) ERCOT ERCOT QSE ERCOT 2-40
Resources LSE TDSP NOIE NOIE PUCT 2.1.2-11 2.1.2-11 ERCOT TDSP ERCOT ERCOT LSE QSE Qualified Scheduling Entity ERCOT ERCOT 1) ERCOT ERCOT NERC ERCOT ERCOT ERCOT ERCOT 2-41
ERCOT QSE REP PGC QSE ERCOT ISO ERCOT ERCOT SB 7 2) QSE QSE ERCOT ERCOT QSE QSE ERCOT 3) TDSP TDSP ERCOT ERCOT 4) Resource Entity PGC NOIE LSE Resource Entity ERCOT Resource Entity Resource Entity ERCOT Resource Entity QSE 5) LSE 2-42
LSE NOIEthe Texas General Land Office LSE Resource Entity QSE (4) 1) ERCOT PJM QSE ERCOT ERCOT QSE 2) ERCOT Day Ahead Scheduling Process Adjustment Period Scheduling Process Real-time 3 (a) Day Ahead Scheduling Process 6:00 16:30 ISO QSE 2-43
2.1.2-12 QSE ERCOT 6AM ERCOT A/S A/S 11AM 11:15A 1PM 16 o 15 o ERCOT A/S A/S QSE ERCOT A/S ERCOT ERCOT A/S o A/S o o [MW] o [$/MW] QSE QSE QSE QSE ERCOT QSE QSE QSE 1:15P QSE 1:30PM A/S A/S A/S QSE A/S A/S Market Clearing Prices for Capacity 3PM 4PM A/S A/S A/S o 1 o o [MW] o [$/MW] o [$/MWh] o [ ] A/S QSE QSE 16 2-44
QSE ERCOT 6PM QSE 6PM 6PM ERCOT, ERCOT Protocols Section 4: Scheduling (b) Adjustment Period Scheduling Process QSE ISO 2.1.2-13 QSE ERCOT 60 A/S A/S A/S A/S QSE 45. ERCOT, ERCOT Protocols Section 4: Scheduling (c) Real Time 1 1 ERCOT ERCOT 2-45
2.1.2-14 ERCOT Balancing Energy Service ERCOT Regulation Service ERCOT 10 Regulation Up Regulation Down 2 AGC Responsive Reserve Service 10 Non-Spinning Reserve Service 30 30 1 Replacement Reserve Service ERCOT (5) 1) Cost of Service PBR 6 9 12 TSP 1 2 2) REP SB7 TDSP 100kW 1999 1 1 6% Price to Beat 2-46
REP 36 40% REP Price to Beat 3) PUCT CTC CTC 2004 CTC 15 transition bonds 2-47