MULBERRY
                                      345
                                     WEST
                                                                              2
BOMSW
                                      345
                                     WEST
                                                                              3
OECCS
                                      345
                                     WEST
                                                                              4
BITTCR
                                      345
                                     WEST
                                                                              5
FSHSW
                                      345
                                     WEST
                                                                              6
FLCNS
                                      345
                                     WEST
                                                                              7
GRSES
                                      345
                                     WEST
                                                                              8
JCKSW
                                      345
                                     WEST
                                                                              9
MDLNE
                                      345
                                     WEST
                                                                             10
MOSSW
                                      345
                                     WEST
                                                                             11
MGSES
                                      345
                                     WEST
                                                                             12
DCTM
                                      345
                                     WEST
                                                                             13
ODEHV
                                      345
                                     WEST
                                                                             14
OKLA
                                      345
                                     WEST
                                                                             15
REDCREEK
                                      345
                                     WEST
                                                                             16
SWESW
                                      345
                                     WEST
                                                                             17
TWINBU
                                      345
                                     WEST
(2)	The West 345 kV Hub Price uses the aggregated Shift Factors of the Hub Buses for each hour of the Settlement Interval of the DAM in the Day-Ahead and is the simple average of the time weighted Hub Bus prices for each 15-minute Settlement Interval in Real-Time, for each Hub Bus included in this Hub.
(3)	The Day-Ahead Settlement Point Price of the Hub for a given Operating Hour is calculated as follows:
      DASPP West345 =		DASL  -  Σc(DAHUBSF West345, c * DASP c),
      		if HBBC West345!=0
      DASPP West345 =		DASPP ERCOT345Bus, if HBBC West345=0
Where:
      DAHUBSF West345, c	=	Σhb(HUBDF hb, West345, c * DAHBSF hb, West345, c)
      DAHBSF hb, West345, c	=	Σpb(HBDF pb, hb, West345, c * DASF pb, hb, West345, c)
      HUBDF hb, West345, c	=	IF(HB West345, c=0, 0, 1 / HB West345, c)
      HBDF pb, hb, West345, c	=	IF(PB hb, West345, c=0, 0, 1 / PB hb, West345, c)
The above variables are defined as follows:
Variable
Unit
Definition
DASPP West345
$/MWh
Day-Ahead Settlement Point PriceThe DAM Settlement Point Price at the Hub, for the hour.
DASL
$/MWh
Day-Ahead System LambdaThe DAM Shadow Price for the system power balance constraint for the hour.
DASP c
$/MWh
Day-Ahead Shadow Price for a binding transmission constraintThe DAM Shadow Price for the constraint c for the hour.
DAHUBSF West345,c
none
Day-Ahead Shift Factor of the Hub The DAM aggregated Shift Factor of a Hub for the constraint c for the hour.
DAHBSF hb,West345,c
none
Day-Ahead Shift Factor of the Hub BusThe DAM aggregated Shift Factor of a Hub Bus hb for the constraint c for the hour.
DASF pb,hb,West345,c
none
Day-Ahead Shift Factor of the power flow busThe DAM Shift Factor of a power flow bus pb that is a component of Hub Bus hb for the constraint c for the hour.
HUBDF hb, West345,c
none
Hub Distribution Factor per Hub Bus in a constraintThe distribution factor of Hub Bus hb for the constraint c for the hour.
HBDF pb, hb, West345,c
none
Hub Bus Distribution Factor per power flow bus of Hub Bus in a constraintThe distribution factor of power flow bus pb that is a component of Hub Bus hb for the constraint c for the hour.
pb
none
An energized power flow bus that is a component of a Hub Bus for the constraint c.
PB hb, West345,c
none
The total number of energized power flow buses in Hub Bus hb for the constraint c.
hb
none
A Hub Bus that is a component of the Hub with at least one energized power flow bus for the constraint c.
HBBC West345
none
The total number of Hub Buses in the Hub with at least one energized component in each Hub Bus in base case.
HB West345,c
none
The total number of Hub Buses in the Hub with at least one energized component in each Hub Bus for the constraint c.
c
none
A DAM binding transmission constraint for the hour caused by either base case or a contingency.
 (4)	The Real-Time Settlement Point Price of the Hub for a given 15-minute Settlement Interval is calculated as follows:
RTSPP West345	=	Max [-$251, (RTRSVPOR + RTRDP +
		(HUBDF hb, West345 * ((RTHBP hb, West345, y * TLMP y) / (TLMP y))))], if HB West345!=0
RTSPP West345	=	RTSPP ERCOT345Bus, if HB West345=0
Where:
      RTRSVPOR 		=	(RNWF y * RTORPA y)
      RTRDP                      		=           (RNWF y * RTORDPA y)
RNWF y		=	TLMP y / TLMP y
RTHBP hb, West345, y	=	(HBDF b, hb, West345 * RTLMP b, hb, West345, y)
HUBDF hb, West345	=	IF(HB West345=0, 0, 1 / HB West345)
HBDF b, hb, West345	=	IF(B hb, West345=0, 0, 1 / B hb, West345)
The above variables are defined as follows:
Variable
Unit
Description
RTSPP West345
$/MWh
Real-Time Settlement Point PriceThe Real-Time Settlement Point Price at the Hub, for the 15-minute Settlement Interval.
RTRSVPOR
$/MWh
Real-Time Reserve Price for On-Line ReservesThe Real-Time Reserve Price for On-Line Reserves for the 15-minute Settlement Interval.
RTORPA y
$/MWh
Real-Time On-Line Reserve Price Adder per intervalThe Real-Time On-Line Reserve Price Adder for the SCED interval y.
RTRDP
$/MWh
Real-Time On-Line Reliability Deployment PriceThe Real-Time price for the 15-minute Settlement Interval, reflecting the impact of reliability deployments on energy prices that are calculated from the Real-Time On-Line Reliability Deployment Price Adder.
RTORDPA y
$/MWh
Real-Time On-Line Reliability Deployment Price AdderThe Real-Time price adder that captures the impact of reliability deployments on energy prices for the SCED interval y.
RNWF y
none
Resource Node Weighting Factor per intervalThe weight used in the Resource Node Settlement Point Price calculation for the portion of the SCED interval y within the Settlement Interval.
RTHBP hb, West345, y
$/MWh
Real-Time Hub Bus Price at Hub Bus per SCED intervalThe Real-Time energy price at Hub Bus hb for the SCED interval y.
RTLMP b, hb, West345, y
$/MWh
Real-Time Locational Marginal Price at Electrical Bus of Hub Bus per intervalThe Real-Time LMP at Electrical Bus b that is a component of Hub Bus hb, for the SCED interval y.
TLMP y
second
Duration of SCED interval per intervalThe duration of the portion of the SCED interval y within the 15-minute Settlement Interval.
HUBDF hb, West345
none
Hub Distribution Factor per Hub BusThe distribution factor of Hub Bus hb.
HBDF b, hb, West345
none
Hub Bus Distribution Factor per Electrical Bus of Hub BusThe distribution factor of Electrical Bus b that is a component of Hub Bus hb.
y
none
A SCED interval in the 15-minute Settlement Interval.  The summation is over the total number of SCED runs that cover the 15-minute Settlement Interval.
b
none
An energized Electrical Bus that is a component of a Hub Bus.
B hb, West345
none
The total number of energized Electrical Buses in Hub Bus hb.
hb
none
A Hub Bus that is a component of the Hub.
HB West345
none
The total number of Hub Buses in the Hub with at least one energized component in each Hub Bus.

[NPRR1007 and NPRR1057:  Replace applicable portions of paragraph (4) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation of NPRR1057:]
(4)	The Real-Time Settlement Point Price of the Hub for a given 15-minute Settlement Interval is calculated as follows:
      RTSPP West345	=	Max [-$251, (RTRDP +
      		(HUBLMP West345, y * RNWF y))]
Where:
      RTRDP                      		=           (RNWF y * RTRDPA y)
      RNWF y		=	TLMP y / TLMP y
The above variables are defined as follows:
Variable
Unit
Description
RTSPP West345
$/MWh
Real-Time Settlement Point PriceThe Real-Time Settlement Point Price at the Hub, for the 15-minute Settlement Interval.
RTRDP
$/MWh
Real-Time Reliability Deployment Price for EnergyThe Real-Time price for the 15-minute Settlement Interval, reflecting the impact of reliability deployments on energy prices that are calculated from the Real-Time Reliability Deployment Price Adder for Energy.
RTRDPA y
$/MWh
Real-Time Reliability Deployment Price Adder for EnergyThe Real-Time Price Adder that captures the impact of reliability deployments on energy prices for the SCED interval y.
HUBLMP West345, y
$/MWh
Hub Locational Marginal PriceThe Hub LMP for the Hub for the SCED Interval y.
RNWF y
none
Resource Node Weighting Factor per intervalThe weight used in the Resource Node Settlement Point Price calculation for the portion of the SCED interval y within the Settlement Interval.
TLMP y
second
Duration of SCED interval per intervalThe duration of the portion of the SCED interval y within the 15-minute Settlement Interval.
y
none
A SCED interval in the 15-minute Settlement Interval.  The summation is over the total number of SCED runs that cover the 15-minute Settlement Interval.

<IP_ADDRESS>	Panhandle 345 kV Hub (Pan 345)
(1)	The Panhandle 345 kV Hub is composed of the following listed Hub Buses:

                               ERCOT Operations

                                      No.
                                    Hub Bus
                                      kV
                                      Hub
                                                                              1
ABERNATH
                                      345
                                      PAN
                                                                              2
AJ_SWOPE
                                      345
                                      PAN
                                                                              3
ALIBATES
                                      345
                                      PAN
                                                                              4
CTT_CROS
                                      345
                                      PAN
                                                                              5
CTT_GRAY
                                      345
                                      PAN
                                                                              6
OGALLALA
                                      345
                                      PAN
                                                                              7
RAILHEAD
                                      345
                                      PAN
                                                                              8
TESLA
                                      345
                                      PAN
                                                                              9
TULECNYN
                                      345
                                      PAN
                                                                             10
W_CW_345
                                      345
                                      PAN
                                                                             11
WHIT_RVR
                                      345
                                      PAN
                                                                             12
WINDMILL
                                      345
                                      PAN
(2)	The Panhandle 345 kV Hub Price uses the aggregated Shift Factors of the Hub Buses for each hour of the Settlement Interval of the DAM in the Day-Ahead and is the simple average of the time weighted Hub Bus prices for each 15-minute Settlement Interval in Real-Time, for each Hub Bus included in this Hub.
(3)	The Day-Ahead Settlement Point Price of the Hub for a given Operating Hour is calculated as follows:
      DASPP Pan345 =		DASL  -  Σc(DAHUBSF Pan345, c * DASP c),
      		if HBBC Pan345!=0
      DASPP Pan345 =		DASPP ERCOT345Bus, if HBBC Pan345=0
Where:
      DAHUBSF Pan345, c	=	Σhb(HUBDF hb, Pan345, c * DAHBSF hb, Pan345, c)
      DAHBSF hb, Pan345, c	=	Σpb(HBDF pb, hb, Pan345, c * DASF pb, hb, Pan345, c)
      HUBDF hb, Pan345, c	=	IF(HB Pan345, c=0, 0, 1 / HB Pan345, c)
      HBDF pb, hb, Pan345, c	=	IF(PB hb, Pan345, c=0, 0, 1 / PB hb, Pan345, c)
The above variables are defined as follows:
Variable
Unit
Definition
DASPP Pan345
$/MWh
Day-Ahead Settlement Point PriceThe DAM Settlement Point Price at the Hub, for the hour.
DASL
$/MWh
Day-Ahead System LambdaThe DAM Shadow Price for the system power balance constraint for the hour.
DASP c
$/MWh
Day-Ahead Shadow Price for a binding transmission constraintThe DAM Shadow Price for the constraint c for the hour.
DAHUBSF Pan345,c
none
Day-Ahead Shift Factor of the Hub The DAM aggregated Shift Factor of a Hub for the constraint c for the hour.
DAHBSF hb,Pan345,c
none
Day-Ahead Shift Factor of the Hub BusThe DAM aggregated Shift Factor of a Hub Bus hb for the constraint c for the hour.
DASF pb,hb,Pan345,c
none
Day-Ahead Shift Factor of the power flow busThe DAM Shift Factor of a power flow bus pb that is a component of Hub Bus hb for the constraint c for the hour.
HUBDF hb, Pan345,c
none
Hub Distribution Factor per Hub Bus in a constraintThe distribution factor of Hub Bus hb for the constraint c for the hour.
HBDF pb, hb, Pan345,c
none
Hub Bus Distribution Factor per power flow bus of Hub Bus in a constraintThe distribution factor of power flow bus pb that is a component of Hub Bus hb for the constraint c for the hour.
pb
none
An energized power flow bus that is a component of a Hub Bus for the constraint c.
PB hb, Pan345,c
none
The total number of energized power flow buses in Hub Bus hb for the constraint c.
hb
none
A Hub Bus that is a component of the Hub with at least one energized power flow bus for the constraint c.
HBBC Pan345
none
The total number of Hub Buses in the Hub with at least one energized component in each Hub Bus in base case.
HB Pan345,c
none
The total number of Hub Buses in the Hub with at least one energized component in each Hub Bus for the constraint c.
c
none
A DAM binding transmission constraint for the hour caused by either base case or a contingency.
(4)	The Real-Time Settlement Point Price of the Hub for a given 15-minute Settlement Interval is calculated as follows:
      RTSPP Pan345	=	Max [-$251, (RTRSVPOR + RTRDP +
      		 (HUBDF hb, Pan345 * ((RTHBP hb, Pan345, y * TLMP y) /           ( TLMP y))))], if HB Pan345!=0
      RTSPP Pan345	=	RTSPP ERCOT345Bus, if HB Pan345=0
Where:
      RTRSVPOR 	=	  (RNWF y * RTORPA y)
      RTRDP                      	=           (RNWF y  * RTORDPA y)
      RNWF y	=	TLMP y / TLMP y
      RTHBP hb, Pan345, y	=	  (HBDF b, hb, Pan345 * RTLMP b, hb, Pan345, y)
      HUBDF hb, Pan345	=	IF(HB Pan345=0, 0, 1 / HB Pan345)
      HBDF b, hb, Pan345	=	IF(B hb, Pan345=0, 0, 1 / B hb, Pan345)
The above variables are defined as follows:
Variable
Unit
Description
RTSPP Pan345
$/MWh
Real-Time Settlement Point PriceThe Real-Time Settlement Point Price at the Hub for the 15-minute Settlement Interval.
RTRSVPOR
$/MWh
Real-Time Reserve Price for On-Line ReservesThe Real-Time Reserve Price for On-Line Reserves for the 15-minute Settlement Interval.
RTORPA y
$/MWh
Real-Time On-Line Reserve Price Adder per intervalThe Real-Time On-Line Reserve Price Adder for the SCED interval y.
RTRDP
$/MWh
Real-Time On-Line Reliability Deployment PriceThe Real-Time price for the 15-minute Settlement Interval, reflecting the impact of reliability deployments on energy prices that are calculated from the Real-Time On-Line Reliability Deployment Price Adder.
RTORDPA y
$/MWh
Real-Time On-Line Reliability Deployment Price AdderThe Real-Time price adder that captures the impact of reliability deployments on energy prices for the SCED interval y.
RNWF y
none
Resource Node Weighting Factor per intervalThe weight used in the Resource Node Settlement Point Price calculation for the portion of the SCED interval y within the Settlement Interval.
RTHBP hb, Pan345, y
$/MWh
Real-Time Hub Bus Price at Hub Bus per SCED intervalThe Real-Time energy price at Hub Bus hb for the SCED interval y.
RTLMP b, hb, Pan345, y
$/MWh
Real-Time Locational Marginal Price at Electrical Bus of Hub Bus per intervalThe Real-Time LMP at Electrical Bus b that is a component of Hub Bus hb for the SCED interval y.
TLMP y
second
Duration of SCED interval per intervalThe duration of the portion of the SCED interval y within the 15-minute Settlement Interval.
HUBDF hb, Pan345
none
Hub Distribution Factor per Hub BusThe distribution factor of Hub Bus hb.
HBDF b, hb, Pan345
none
Hub Bus Distribution Factor per Electrical Bus of Hub BusThe distribution factor of Electrical Bus b that is a component of Hub Bus hb.
y
none
A SCED interval in the 15-minute Settlement Interval.  The summation is over the total number of SCED runs that cover the 15-minute Settlement Interval.
b
none
An energized Electrical Bus that is a component of a Hub Bus.
B hb, Pan345
none
The total number of energized Electrical Buses in Hub Bus hb.
hb
none
A Hub Bus that is a component of the Hub.
HB Pan345
none
The total number of Hub Buses in the Hub with at least one energized component in each Hub Bus.

[NPRR1007 and NPRR1057:  Replace applicable portions of paragraph (4) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1057:]
(4)	The Real-Time Settlement Point Price of the Hub for a given 15-minute Settlement Interval is calculated as follows:
      RTSPP Pan345	=	Max [-$251, (RTRDP +
      		(HUBLMP Pan345, y * RNWF y ))]
Where:
      RTRDP                      	=           (RNWF y  * RTRDPA y)
      RNWF y	=	TLMP y / TLMP y
The above variables are defined as follows:
Variable
Unit
Description
RTSPP Pan345
$/MWh
Real-Time Settlement Point PriceThe Real-Time Settlement Point Price at the Hub for the 15-minute Settlement Interval.
RTRDP
$/MWh
Real-Time Reliability Deployment Price for EnergyThe Real-Time price for the 15-minute Settlement Interval, reflecting the impact of reliability deployments on energy prices that are calculated from the Real-Time Reliability Deployment Price Adder for Energy.
RTRDPA y
$/MWh
Real-Time Reliability Deployment Price Adder for EnergyThe Real-Time Price Adder that captures the impact of reliability deployments on energy prices for the SCED interval y.
HUBLMP Pan345, y
$/MWh
Hub Locational Marginal PriceThe Hub LMP for the Hub for the SCED Interval y.
RNWF y
none
Resource Node Weighting Factor per intervalThe weight used in the Resource Node Settlement Point Price calculation for the portion of the SCED interval y within the Settlement Interval.
TLMP y
second
Duration of SCED interval per intervalThe duration of the portion of the SCED interval y within the 15-minute Settlement Interval.
y
none
A SCED interval in the 15-minute Settlement Interval.  The summation is over the total number of SCED runs that cover the 15-minute Settlement Interval.

[NPRR941, NPRR1007, and NPRR1057:  Insert applicable portions of Section <IP_ADDRESS> below upon system implementation for NPRR941 or NPRR1057; or upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; and renumber accordingly:]
<IP_ADDRESS>	Lower Rio Grande Valley Hub (LRGV 138/345)
(1)	The Lower Rio Grande Valley Hub 138/345 kV Hub is composed of the following listed Hub Buses:

ERCOT Operations

No.
                                    Hub Bus
                                      kV
                                      Hub
                                                                              1
AIRPORT
                                      138
                                     LRGV
                                                                              2
ALBERTA
                                      138
                                     LRGV
                                                                              3
BATES
                                      138
                                     LRGV
                                                                              4
FRONTERA
                                      138
                                     LRGV
                                                                              5
GARZA
                                      138
                                     LRGV
                                                                              6
HARLNSW
                                      138
                                     LRGV
                                                                              7
HEC
                                      138
                                     LRGV
                                                                              8
KEY_SW
                                      138
                                     LRGV
                                                                              9
LA_PALMA_345
                                      345
                                     LRGV
                                                                             10
LA_PALMA_138
                                      138
                                     LRGV
                                                                             11
LASPULGA
                                      138
                                     LRGV
                                                                             12
LISTON
                                      138
                                     LRGV
                                                                             13
LOMA_ALT
                                      138
                                     LRGV
                                                                             14
MARCONI
                                      138
                                     LRGV
                                                                             15
MILHWY
                                      138
                                     LRGV
                                                                             16
MILITARY
                                      138
                                     LRGV
                                                                             17
MV_WEDN4
                                      138
                                     LRGV
                                                                             18
N_MCALLN
                                      138
                                     LRGV
                                                                             19
NEDIN_345
                                      345
                                     LRGV
                                                                             20
NEDIN_138
                                      138
                                     LRGV
                                                                             21
OLEANDER
                                      138
                                     LRGV
                                                                             22
P_ISABEL
                                      138
                                     LRGV
                                                                             23
PALMHRTP
                                      138
                                     LRGV
                                                                             24
PALMITO_345
                                      345
                                     LRGV
                                                                             25
PALMITO_138
                                      138
                                     LRGV
                                                                             26
PAREDES
                                      138
                                     LRGV
                                                                             27
PHARMVEC
                                      138
                                     LRGV
                                                                             28
PHARR
                                      138
                                     LRGV
                                                                             29
PRICE_RD
                                      138
                                     LRGV
                                                                             30
RAILROAD
                                      138
                                     LRGV
                                                                             31
RAYMND2
                                      138
                                     LRGV
                                                                             32
REDTAP
                                      138
                                     LRGV
                                                                             33
RIO_GRAN
                                      138
                                     LRGV
                                                                             34
RIOHONDO_345
                                      345
                                     LRGV
                                                                             35
RIOHONDO_138
                                      138
                                     LRGV
                                                                             36
ROMA_SW
                                      138
                                     LRGV
                                                                             37
S_MCALLN
                                      138
                                     LRGV
                                                                             38
SCARBIDE
                                      138
                                     LRGV
                                                                             39
SILASRAY
                                      138
                                     LRGV
                                                                             40
STEWART
                                      138
                                     LRGV
                                                                             41
WESLACO
                                      138
                                     LRGV
ΣcΣhbΣpb(2)	The Lower Rio Grande Valley 138/345 kV Hub Price uses the aggregated Shift Factors of the Hub Buses for each hour of the Settlement Interval of the DAM in the Day-Ahead and is the simple average of the time weighted Hub Bus prices for each 15-minute Settlement Interval in Real-Time, for each Hub Bus included in this Hub.
(3)	The Day-Ahead Settlement Point Price of the Hub for a given Operating Hour is calculated as follows:
      DASPP LRGV 138/345 =	DASL  -  ΣcΣc(DAHUBSF LRGV 138/345, c * DASP c),
      		if HBBC LRGV138/345!=0
      DASPP LRGV138/345 =	DASPP ERCOT345Bus, if HBBC LRGV138/345=0
Where:
      DAHUBSF LRGV138/345, c	=        Σhb(HUBDF hb, LRGV138/345, c * DAHBSF hb, LRGV138/345, c)
      DAHBSF hb, LRGV138/345, c	=	Σpb(HBDF pb, hb, LRGV138/345, c * DASF pb, hb, LRGV138/345, c)
      HUBDF hb, LRGV138/345, c	=	IF(HB LRGV138/345, c=0, 0, 1 / HB LRGV138/345, c)
      HBDF pb, hb, LRGV138/345, c	=	IF(PB hb, LRGV138/345, c=0, 0, 1 / PB hb, LRGV138/345, c)
The above variables are defined as follows:
Variable
Unit
Definition
DASPP LRGV138/345
$/MWh
Day-Ahead Settlement Point PriceThe DAM Settlement Point Price at the Hub, for the hour.
DASL
$/MWh
Day-Ahead System LambdaThe DAM Shadow Price for the system power balance constraint for the hour.
DASP c
$/MWh
Day-Ahead Shadow Price for a binding transmission constraintThe DAM Shadow Price for the constraint c for the hour.
DAHUBSF LRGV138/345,c
none
Day-Ahead Shift Factor of the Hub The DAM aggregated Shift Factor of a Hub for the constraint c for the hour.
DAHBSF hb, LRGV138/345,c
none
Day-Ahead Shift Factor of the Hub BusThe DAM aggregated Shift Factor of a Hub Bus hb for the constraint c for the hour.
DASF pb,hb, LRGV138/345,c
none
Day-Ahead Shift Factor of the power flow busThe DAM Shift Factor of a power flow bus pb that is a component of Hub Bus hb for the constraint c for the hour.
HUBDF hb, LRGV138/345,c
none
Hub Distribution Factor per Hub Bus in a constraintThe distribution factor of Hub Bus hb for the constraint c for the hour.
HBDF pb, hb, LRGV138/345,c
none
Hub Bus Distribution Factor per power flow bus of Hub Bus in a constraintThe distribution factor of power flow bus pb that is a component of Hub Bus hb for the constraint c for the hour.
pb
none
An energized power flow bus that is a component of a Hub Bus for the constraint c.
PB hb, LRGV138/345,c
none
The total number of energized power flow buses in Hub Bus hb for the constraint c.
hb
none
A Hub Bus that is a component of the Hub with at least one energized power flow bus for the constraint c.
HBBC LRGV138/345
none
The total number of Hub Buses in the Hub with at least one energized component in each Hub Bus in base case.
HB LRGV138/345,c
none
The total number of Hub Buses in the Hub with at least one energized component in each Hub Bus for the constraint c.
c
none
A DAM binding transmission constraint for the hour caused by either base case or a contingency.
(4)	The Real-Time Settlement Point Price of the Hub for a given 15-minute Settlement Interval is calculated as follows:
      RTSPP LRGV138/345          =	Max [-$251, (RTRDP +
      		Σy(HUBLMP LRGV138/345, y * RNWF y))]
Where:
      RTRDP                      	=          Σy(RNWF y  * RTRDPA y)
      RNWF y	=	TLMP y / ΣyTLMP y
The above variables are defined as follows:
Variable
Unit
Description
RTSPP LRGV138/345kV
$/MWh
Real-Time Settlement Point PriceThe Real-Time Settlement Point Price at the Hub for the 15-minute Settlement Interval.
RTRDP
$/MWh
Real-Time Reliability Deployment Price for EnergyThe Real-Time price for the 15-minute Settlement Interval, reflecting the impact of reliability deployments on energy prices that are calculated from the Real-Time Reliability Deployment Price Adder for Energy.
RTRDPA y
$/MWh
Real-Time Reliability Deployment Price Adder for EnergyThe Real-Time Price Adder that captures the impact of reliability deployments on energy prices for the SCED interval y.
HUBLMP LRGV138/345, y
$/MWh
Hub Locational Marginal PriceThe Hub LMP for the Hub for the SCED Interval y.
RNWF y
none
Resource Node Weighting Factor per intervalThe weight used in the Resource Node Settlement Point Price calculation for the portion of the SCED interval y within the Settlement Interval.
TLMP y
second
Duration of SCED interval per intervalThe duration of the portion of the SCED interval y within the 15-minute Settlement Interval.
y
none
A SCED interval in the 15-minute Settlement Interval.  The summation is over the total number of SCED runs that cover the 15-minute Settlement Interval.

<IP_ADDRESS>	ERCOT Hub Average 345 kV Hub (ERCOT 345)
(1)	The ERCOT Hub Average 345 kV Hub price for Day-Ahead is calculated for each hour using the aggregated Shift Factors of four Hubs: the North 345 kV Hub, the South 345 kV Hub, the Houston 345 kV Hub, and the West 345 kV Hub.  The ERCOT Hub Average 345 kV Hub price for Real-Time is the simple average of four prices from the applicable time period: the North 345 kV Hub price, the South 345 kV Hub price, the Houston 345 kV Hub price, and the West 345 kV Hub price.  The Panhandle 345 kV Hub is not included in either the Day-Ahead or Real-Time ERCOT Hub Average 345 kV Hub price.

[NPRR941:  Replace paragraph (1) above upon system implementation:]
(1)	The ERCOT Hub Average 345 kV Hub price for Day-Ahead is calculated for each hour using the aggregated Shift Factors of four Hubs: the North 345 kV Hub, the South 345 kV Hub, the Houston 345 kV Hub, and the West 345 kV Hub.  The ERCOT Hub Average 345 kV Hub price for Real-Time is the simple average of four prices from the applicable time period: the North 345 kV Hub price, the South 345 kV Hub price, the Houston 345 kV Hub price, and the West 345 kV Hub price.  The Panhandle 345 kV Hub and the Lower Rio Grande Valley 138/345 kV Hub are not included in either the Day-Ahead or Real-Time ERCOT Hub Average 345 kV Hub price.
(2)	The Day-Ahead Settlement Point Price for the Hub "ERCOT 345" for a given Operating Hour is calculated as follows:
      DASPP ERCOT345	=	DASL  -  Σc(DAHUBSF ERCOT345, c * DASP c),
      		if HBBC ERCOT345Bus!=0
      DASPP ERCOT345	=	DASPP ERCOT345Bus, if HBBC ERCOT345Bus=0
Where:
      DAHUBSF ERCOT345, c   = (DAHUBSF North345, c + DAHUBSF South345, c +
      	DAHUBSF Houston345, c + DAHUBSF West345, c) / 4
The above variables are defined as follows:
Variable
Unit
Definition
DASPP ERCOT345
$/MWh
Day-Ahead Settlement Point Price at ERCOT 345The DAM Settlement Point Price at ERCOT 345 Hub for the hour.
DASL
$/MWh
Day-Ahead System LambdaThe DAM Shadow Price for the system power balance constraint for the hour.
DASP c
$/MWh
Day-Ahead Shadow Price for a binding transmission constraintThe DAM Shadow Price for the constraint c for the hour.
DAHUBSF ERCOT345,c
none
Day-Ahead Shift Factor of ERCOT 345 The DAM aggregated Shift Factor of ERCOT 345 Hub for the constraint c for the hour.
DAHUBSF North345,c
none
Day-Ahead Shift Factor of North 345The DAM aggregated Shift Factor of the North 345 Hub for the constraint c for the hour.
DAHUBSF South345,c
none
Day-Ahead Shift Factor of South 345The DAM aggregated Shift Factor of the South 345 Hub for the constraint c for the hour.
DAHUBSF Houston345,c
none
Day-Ahead Shift Factor of Houston 345The DAM aggregated Shift Factor of the Houston 345 Hub for the constraint c for the hour.
DAHUBSF West345,c
none
Day-Ahead Shift Factor of West 345The DAM aggregated Shift Factor of the West 345 Hub for the constraint c for the hour.
HBBC ERCOT345Bus
none
The total number of Hub Buses in the ERCOT Bus Average 345 kV Hub (ERCOT 345 Bus) with at least one energized component in each Hub Bus in base case.  The Hub "ERCOT 345 Bus" includes any Hub Bus defined in the Hub "North 345", "South 345", "Houston 345" and "West 345".
c
none
A DAM binding transmission constraint for the hour caused by either base case or a contingency.
(3)	The Real-Time Settlement Point Price for the Hub "ERCOT 345" for a given 15-minute Settlement Interval is calculated as follows:
RTSPP ERCOT345	=	(RTSPP North345 + RTSPP South345 + RTSPP Houston345 + RTSPP West345) / 4
The above variables are defined as follows:
Variable
Unit
Definition
RTSPP ERCOT345
$/MWh
Real-Time Settlement Point Price at ERCOT 345The Real-Time Settlement Point Price at ERCOT 345 Hub for the 15-minute Settlement Interval.
RTSPP North345
$/MWh
Real-Time Settlement Point Price at North 345The Real-Time Settlement Point Price at the North 345 Hub for the 15-minute Settlement Interval.
RTSPP South345
$/MWh
Real-Time Settlement Point Price at South 345The Real-Time Settlement Point Price at the South 345 Hub for the 15-minute Settlement Interval.
RTSPP Houston345
$/MWh
Real-Time Settlement Point Price at Houston 345The Real-Time Settlement Point Price at the Houston 345 Hub for the 15-minute Settlement Interval.
RTSPP West345
$/MWh
Real-Time Settlement Point Price at West 345The Real-Time Settlement Point Price at the West 345 Hub for the 15-minute Settlement Interval.
<IP_ADDRESS>	ERCOT Bus Average 345 kV Hub (ERCOT 345 Bus)
(1)	The ERCOT Bus Average 345 kV Hub is composed of the Hub Buses listed in Section <IP_ADDRESS>, North 345 kV Hub (North 345); Section <IP_ADDRESS>, South 345 kV Hub (South 345); Section <IP_ADDRESS>, Houston 345 kV Hub (Houston 345); and Section <IP_ADDRESS>, West 345 kV Hub (West 345).  The Panhandle 345 kV Hub is not included in the ERCOT Bus Average 345 kV Hub price.

[NPRR941:  Replace paragraph (1) above upon system implementation:]
(1)	The ERCOT Bus Average 345 kV Hub is composed of the Hub Buses listed in Section <IP_ADDRESS>, North 345 kV Hub (North 345); Section <IP_ADDRESS>, South 345 kV Hub (South 345); Section <IP_ADDRESS>, Houston 345 kV Hub (Houston 345); and Section <IP_ADDRESS>, West 345 kV Hub (West 345).  The Panhandle 345 kV Hub and the Lower Rio Grande Valley 138/345 kV Hub are not included in the ERCOT Bus Average 345 kV Hub price.
(2)	The ERCOT Bus Average 345 kV Hub uses the aggregated Shift Factors of the Hub Buses for each hour of the Settlement Interval of the DAM in the Day-Ahead and is the simple average of the time weighted Hub Bus prices for each 15-minute Settlement Interval in Real-Time, for each Hub Bus included in this Hub.
(3)	The Day-Ahead Settlement Point Price of the Hub for a given Operating Hour is calculated as follows:
      DASPP ERCOT345Bus =	DASL  -  Σc(DAHUBSF ERCOT345Bus, c * DASP c),
      		if HBBC ERCOT345Bus!=0
      DASPP ERCOT345Bus =	0, if HBBC ERCOT345Bus=0
Where:
      DAHUBSF ERCOT345Bus, c   =	Σhb(HUBDF hb, ERCOT345Bus, c * DAHBSF hb, ERCOT345Bus, c)
      DAHBSF hb, ERCOT345Bus, c  =	Σpb(HBDF pb, hb, ERCOT345Bus, c * DASF pb, hb, ERCOT345Bus, c)
      HUBDF hb, ERCOT345Bus, c	=	IF(HB ERCOT345Bus, c=0, 0, 1 / HB ERCOT345Bus, c)
      HBDF pb, hb, ERCOT345Bus, c	=	IF(PB hb, ERCOT345Bus, c=0, 0, 1 / PB hb, ERCOT345Bus, c)
The above variables are defined as follows:
Variable
Unit
Definition
DASPP ERCOT345Bus
$/MWh
Day-Ahead Settlement Point PriceThe DAM Settlement Point Price at the Hub, for the hour.
DASL
$/MWh
Day-Ahead System LambdaThe DAM Shadow Price for the system power balance constraint for the hour.
DASP c
$/MWh
Day-Ahead Shadow Price for a binding transmission constraintThe DAM Shadow Price for the constraint c for the hour.
DAHUBSF ERCOT345Bus,c
none
Day-Ahead Shift Factor of the Hub The DAM aggregated Shift Factor of a Hub for the constraint c for the hour.
DAHBSF hb,ERCOT345Bus,c
none
Day-Ahead Shift Factor of the Hub BusThe DAM aggregated Shift Factor of a Hub Bus hb for the constraint c for the hour.
DASF pb,hb,ERCOT345Bus,c
none
Day-Ahead Shift Factor of the power flow busThe DAM Shift Factor of a power flow bus pb that is a component of Hub Bus hb for the constraint c for the hour.
HUBDF hb,ERCOT345Bus,c
none
Hub Distribution Factor per Hub Bus in a constraintThe distribution factor of Hub Bus hb for the constraint c for the hour.
HBDF pb, hb, ERCOT345Bus,c
none
Hub Bus Distribution Factor per power flow bus of Hub Bus in a constraintThe distribution factor of power flow bus pb that is a component of Hub Bus hb for the constraint c for the hour.
pb
none
An energized power flow bus that is a component of a Hub Bus for the constraint c.
PB hb, ERCOT345Bus,c
none
The total number of energized power flow buses in Hub Bus hb for the constraint c.
hb
none
A Hub Bus that is a component of the ERCOT Bus Average 345 kV Hub (ERCOT 345 Bus) with at least one energized power flow bus for the constraint c. The Hub "ERCOT 345 Bus" includes any Hub Bus defined in the Hub "North 345", "South 345", "Houston 345" and "West 345".
HBBC ERCOT345Bus
none
The total number of Hub Buses in the ERCOT Bus Average 345 kV Hub (ERCOT 345 Bus) with at least one energized component in each Hub Bus in base case. The Hub "ERCOT 345 Bus" includes any Hub Bus defined in the Hub "North 345", "South 345", "Houston 345" and "West 345".
HB ERCOT345Bus,c
none
The total number of Hub Buses in the ERCOT Bus Average 345 kV Hub (ERCOT 345 Bus) with at least one energized component in each Hub Bus for the constraint c. The Hub "ERCOT 345 Bus" includes any Hub Bus defined in the Hub "North 345", "South 345", "Houston 345" and "West 345".
c
none
A DAM binding transmission constraint for the hour caused by either base case or a contingency.
 (4)	The Real-Time Settlement Point Price of the Hub for a given 15-minute Settlement Interval is calculated as follows:
RTSPP ERCOT345Bus	=	Max [-$251, (RTRSVPOR + RTRDP +
		(HUBDF hb, ERCOT345Bus * ((RTHBP hb, ERCOT345Bus, y * TLMP y) / (TLMP y))))], if HB ERCOT345Bus !=0
RTSPP ERCOT345Bus	=	0, if HB ERCOT345Bus =0
Where:
      RTRSVPOR 	=	(RNWF y * RTORPA y)
      RTRDP                      	 =           (RNWF y * RTORDPA y)
RNWF y		=	TLMP y / TLMP y
RTHBP hb, ERCOT345Bus, y	=	(HBDF b, hb, ERCOT345Bus * RTLMP b, hb, ERCOT345Bus, y)
HUBDF hb, ERCOT345Bus	=	1 / (HB North345 + HB South345 + HB Houston345 + HB West345)
      If Electrical Bus b is a component of "North 345"
		HBDF b, hb, ERCOT345Bus	=	IF(B hb, North345=0, 0, 1 / B hb, North345)
      Otherwise
		If Electrical Bus b is a component of "South 345"
			HBDF b, hb, ERCOT345Bus	=	IF(B hb, South345=0, 0, 1 / B hb, South345)
      Otherwise
			If Electrical Bus b is a component of "Houston 345"
				HBDF b, hb, ERCOT345Bus	=	IF(B hb, Houston345=0, 0, 1 / B hb, Houston345)
            Otherwise
				HBDF b, hb, ERCOT345Bus	=	IF(B hb, West345=0, 0, 1 / B hb, West345)

The above variables are defined as follows:
Variable
Unit
Description
RTSPP ERCOT345Bus
$/MWh
Real-Time Settlement Point PriceThe Real-Time Settlement Point Price at the Hub, for the 15-minute Settlement Interval.
RTRSVPOR
$/MWh
Real-Time Reserve Price for On-Line ReservesThe Real-Time Reserve Price for On-Line Reserves for the 15-minute Settlement Interval.
RTORPA y
$/MWh
Real-Time On-Line Reserve Price Adder per intervalThe Real-Time On-Line Reserve Price Adder for the SCED interval y.
RTRDP
$/MWh
Real-Time On-Line Reliability Deployment PriceThe Real-Time price for the 15-minute Settlement Interval, reflecting the impact of reliability deployments on energy prices that are calculated from the Real-Time On-Line Reliability Deployment Price Adder.
RTORDPA y
$/MWh
Real-Time On-Line Reliability Deployment Price AdderThe Real-Time price adder that captures the impact of reliability deployments on energy prices for the SCED interval y.
RNWF y
none
Resource Node Weighting Factor per intervalThe weight used in the Resource Node Settlement Point Price calculation for the portion of the SCED interval y within the Settlement Interval.
RTHBP hb, ERCOT345Bus, y
$/MWh
Real-Time Hub Bus Price at Hub Bus per SCED intervalThe Real-Time energy price at Hub Bus hb for the SCED interval y.
RTLMP b, hb, ERCOT345Bus, y
$/MWh
Real-Time Locational Marginal Price at Electrical Bus of Hub Bus per intervalThe Real-Time LMP at Electrical Bus b that is a component of Hub Bus hb, for the SCED interval y.
TLMP y
second
Duration of SCED interval per intervalThe duration of the portion of the SCED interval y within the 15-minute Settlement Interval.
HUBDF hb, ERCOT345Bus
none
Hub Distribution Factor per Hub BusThe distribution factor of Hub Bus hb.
HBDF b, hb, ERCOT345Bus
none
Hub Bus Distribution Factor per Electrical Bus of Hub BusThe distribution factor of Electrical Bus b that is a component of Hub Bus hb.
y
none
A SCED interval in the 15-minute Settlement Interval.  The summation is over the total number of SCED runs that cover the 15-minute Settlement Interval.
b
none
An energized Electrical Bus that is a component of a Hub Bus.
B hb, North345
none
The total number of energized Electrical Buses in Hub Bus hb that is a component of "North 345."
B hb, South345
none
The total number of energized Electrical Buses in Hub Bus hb that is a component of "South 345."
B hb, Houston345
none
The total number of energized Electrical Buses in Hub Bus hb that is a component of "Houston 345."
B hb, West345
none
The total number of energized Electrical Buses in Hub Bus hb that is a component of "West 345."
hb
none
A Hub Bus that is a component of the Hub.
HB North345
none
The total number of Hub Buses in "North 345."
HB South345
none
The total number of Hub Buses in "South 345."
HB Houston345
none
The total number of Hub Buses in "Houston 345."
HB West345
none
The total number of Hub Buses in "West 345."

[NPRR1007 and NPRR1057:  Replace applicable portions of paragraph (4) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1057:]
(4)	The Real-Time Settlement Point Price of the Hub for a given 15-minute Settlement Interval is calculated as follows:
      RTSPP ERCOT345Bus	=	Max [-$251, (RTRDP + (HUBLMPERCOT345Bus,y * RNWF y))]
Where:
      RTRDP                      	 =           (RNWF y * RTRDPA y)
      RNWF y		=	TLMP y / TLMP y

The above variables are defined as follows:
Variable
Unit
Description
RTSPP ERCOT345Bus
$/MWh
Real-Time Settlement Point PriceThe Real-Time Settlement Point Price at the Hub, for the 15-minute Settlement Interval.
RTRDP
$/MWh
Real-Time Reliability Deployment Price for EnergyThe Real-Time price for the 15-minute Settlement Interval, reflecting the impact of reliability deployments on energy prices that are calculated from the Real-Time Reliability Deployment Price Adder for Energy.
RTRDPA y
$/MWh
Real-Time Reliability Deployment Price Adder for EnergyThe Real-Time Price Adder that captures the impact of reliability deployments on energy prices for the SCED interval y.
HUBLMP ERCOT345Bus,y
$/MWh
Hub Locational Marginal Price for the ERCOT345BusThe Hub LMP for the ERCOT Bus Average 345 kV Hub (ERCOT 345 Bus), for the SCED Interval y.
RNWF y
none
Resource Node Weighting Factor per intervalThe weight used in the Resource Node Settlement Point Price calculation for the portion of the SCED interval y within the Settlement Interval.
TLMP y
second
Duration of SCED interval per intervalThe duration of the portion of the SCED interval y within the 15-minute Settlement Interval.
y
none
A SCED interval in the 15-minute Settlement Interval.  The summation is over the total number of SCED runs that cover the 15-minute Settlement Interval.

3.5.3	ERCOT Responsibilities for Managing Hubs
<IP_ADDRESS>	Posting of Hub Buses and Electrical Buses included in Hubs
(1)	ERCOT shall post a list of all the Hub Buses included in each Hub on the ERCOT website.  The list must include the name and kV rating for each Electrical Bus included in each Hub Bus.
<IP_ADDRESS>	Calculation of Hub Prices
(1)	ERCOT shall calculate Hub prices for each Settlement Interval as identified in the description of each Hub.
3.6	Load Participation
3.6.1	Load Resource Participation
(1)	A Load Resource may participate by providing:
(a)	Ancillary Service:
(i)	Regulation Up (Reg-Up) Service as a Controllable Load Resource capable of providing Primary Frequency Response;
(ii)	Regulation Down (Reg-Down) Service as a Controllable Load Resource capable of providing Primary Frequency Response;
(iii)	Responsive Reserve (RRS) as a Controllable Load Resource qualified for Security-Constrained Economic Dispatch (SCED) Dispatch and capable of providing Primary Frequency Response, or as a Load Resource controlled by high-set under-frequency relay;
[NPRR863:  Insert paragraph (iv) below upon system implementation and renumber accordingly:]
(iv)	ERCOT Contingency Reserve Service (ECRS) as a Controllable Load Resource qualified for SCED Dispatch and capable of providing Primary Frequency Response, or as a Load Resource that may or may not be controlled by high-set under-frequency relay;
(iv)	Non-Spinning Reserve (Non-Spin) as a Controllable Load Resource qualified for SCED Dispatch or as a Load Resource that is not a Controllable Load Resource and that is not controlled by under-frequency relay; and
(v)	A Load Resource that is not a Controllable Load Resource cannot simultaneously provide Non-Spin and RRS in Real-Time;
(b)	Energy in the form of Demand response from a Controllable Load Resource in Real-Time via SCED;
(c)	Emergency Response Service (ERS) for hours in which the Load Resource does not have an Ancillary Service Resource Responsibility; and
[NPRR1007:  Replace paragraph (c) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project:]
      (c)	Emergency Response Service (ERS) for hours in which the Load Resource has a Resource Status of OUTL; and
(d)	Voluntary Load response in Real-Time.
      (2)	Except for voluntary Load response and ERS, loads participating in any ERCOT market must be registered as a Load Resource and are subject to qualification testing administered by ERCOT.
      (3)	All ERCOT Settlements resulting from Load Resource participation are made only with the Qualified Scheduling Entity (QSE) representing the Load Resource.
(4)	A QSE representing a Load Resource and submitting a bid to buy for participation in SCED, as described in Section <IP_ADDRESS>, RTM Energy Bids, must represent the Load Serving Entity (LSE) serving the Load of the Load Resource.  If the Load Resource is an Aggregate Load Resource (ALR), the QSE must represent the LSE serving the Load of all sites within the ALR.
(5)	The Settlement Point for a Controllable Load Resource is its Load Zone Settlement Point.  For an Energy Storage Resource (ESR), the Settlement Point for the charging Load withdrawn by the modeled Controllable Load Resource associated with the ESR is the Resource Node of the modeled Generation Resource associated with the ESR.
(6)	QSEs shall not submit offers for Load Resources containing sites associated with a Dynamically Scheduled Resource (DSR).
[NPRR1000:  Delete paragraph (6) above upon system implementation and renumber accordingly.]
(7)	Each Resource Entity that represents one or more Load Resources shall ensure that each Load Resource it represents meets at least one of the following conditions:
      (a)	The Load Resource is not located behind an Electric Service Identifier (ESI ID) that corresponds to a Critical Load;
      (b)	The Load Resource is located behind an ESI ID that corresponds to a Critical Load, but the Load Resource is not a Critical Load and does not include a Critical Load; or
      (c)	The Load Resource is located behind an ESI ID that corresponds to a Critical Load, but electric service from the ERCOT System is not required for the provision of the critical service due to the availability of back-up generation or other technologies at the site.
(8)	As a condition of obtaining and maintaining registration as a Load Resource, the Resource Entity for the Load Resource must have submitted an attestation, in a form deemed acceptable by ERCOT, stating that one of the conditions set forth in paragraph (7) above is true, and that if either of the conditions in paragraph (7)(b) or (7)(c) is true, then all of the Load Resource's offered Demand response capacity will be available if deployed by ERCOT during an emergency.
(9)	Each QSE that represents one or more ERS Resources shall ensure that each ERS Resource identified in any ERS Submission Form submitted by the QSE meets at least one of the following conditions:
      (a) 	The ERS Resource and each site within the ERS Resource are not located behind an ESI ID or unique meter identifier that corresponds to a Critical Load and are not used to support a Critical Load; or
      (b) 	The ERS Resource or one or more sites within the ERS Resource are behind an ESI ID or unique meter identifier that corresponds to a Critical Load, but the ERS Resource and each site within the ERS Resource are not a Critical Load, do not include a Critical Load, and are not used to support a Critical Load; or
      (c) 	The ERS Resource or one or more sites within the ERS Resource are behind an ESI ID or unique meter identifier that corresponds to a Critical Load, but electric service from the ERCOT System is not required for the provision of the critical service due to the availability of back-up generation or other technologies at the site, and neither the ERS Resource nor any site within the ERS Resource is used to support a Critical Load.
3.6.2	Decision Making Entity for a Resource
(1)	Each Resource Entity that owns a Resource, except for a Load Resource that is not SCED qualified, shall submit a declaration to ERCOT, using Section 23, Form C, Managed Capacity Declaration, as to which Decision Making Entity (DME) has control of each of its Resources.  The declaration shall be signed by the Authorized Representative of the Resource Entity.  In addition, each Resource Entity that owns a Resource, except for a Load Resource that is not SCED qualified, shall notify ERCOT of any known changes in that declaration no later than 14 days prior to the date that the change takes effect, or as soon as possible in a situation where the Resource Entity is unable to meet the 14-day Notice requirement.  However, in no event may the Resource Entity inform ERCOT later than 72 hours before the date on which the change in DME takes effect.  Upon ERCOT's request, each Resource Entity that owns a Resource, except for a Load Resource that is not SCED qualified, shall provide ERCOT with sufficient information or documentation to verify the DME's control of the Resource.  ERCOT shall update the DME for a Resource effective the first Operating Hour of the Operating Day after ERCOT satisfactorily confirms the Resource Entity's most recent declaration, but not sooner than the effective date specified on the Resource Entity's most recent declaration.
3.7	Resource Parameters
(1)	A Resource Entity shall register Generation Resources, Settlement Only Generators (SOGs), and Load Resources pursuant to Planning Guide Section 6.8, Resource Registration Procedures.  The Resource Parameters, listed in Section 3.7.1, Resource Parameter Criteria, are a subset of Resource Registration data defined in the Resource Registration Glossary.
[NPRR995 and NPRR1002:  Replace applicable portions of paragraph (1) above with the following upon system implementation:]
(1)	A Resource Entity shall register its Generation Resources, Energy Storage Resources (ESRs), Settlement Only Generators (SOGs), Settlement Only Energy Storage Systems (SOESSs), and Load Resources pursuant to Planning Guide Section 6.8, Resource Registration Procedures.  The Resource Parameters, listed in Section 3.7.1, Resource Parameter Criteria, are a subset of Resource Registration data defined in the Resource Registration Glossary.
(2)	ERCOT shall provide each Qualified Scheduling Entity (QSE) that represents a Resource the ability to submit changes to Resource Parameters for that Resource as described in Section 3.7.1.
(3)	The QSE may revise Resource Parameters only with sufficient documentation to justify a change in Resource Parameters.
(4)	ERCOT shall use the Resource Parameters as inputs into the Day-Ahead Market (DAM), Reliability Unit Commitment (RUC), Security-Constrained Economic Dispatch (SCED), Resource Limit Calculator, Load Frequency Control (LFC), and other ERCOT business processes.
(5)	The Independent Market Monitor (IMM) may require the QSE to provide justification for the Resource Parameters submitted.
3.7.1	Resource Parameter Criteria
<IP_ADDRESS>	Generation Resource Parameters
(1)	Generation Resource Parameters that may be modified, with documented reason for change, by the QSE for immediate use upon ERCOT validation include:
(a)	Normal Ramp Rate curve;
(b)	Emergency Ramp Rate curve;
(c)	Minimum On-Line time;
(d)	Minimum Off-Line time;
(e)	Maximum On-Line time;
(f)	Maximum daily starts;
(g)	Maximum weekly starts;
(h)	Maximum weekly energy;
(i)	Hot start time;
(j)	Intermediate start time;
(k)	Cold start time;
(l)	Hot to intermediate time; and
(m)	Intermediate to cold time.
<IP_ADDRESS>	Load Resource Parameters
(1)	Resource Parameters that may be modified, with documented reason for change, by the QSE for immediate use upon ERCOT validation, which may be adjusted to reflect Distribution Losses in accordance with Section <IP_ADDRESS>, General Capacity Testing Requirements, include the following for each of its Load Resources that is a non-Controllable Load Resource:
      (a)	Maximum interruption time;
      (b)	Maximum daily deployments;
      (c)	Maximum weekly deployments;
      (d)	Maximum weekly energy;
      (e)	Minimum notice time;

(f)	Minimum interruption time; and
(g)	Minimum restoration time.
(2)	Resource Parameters that may be modified, with documented reason for change, by the QSE for immediate use upon ERCOT validation, which may be adjusted to reflect Distribution Losses in accordance with Section <IP_ADDRESS>, include the following for each of its Controllable Load Resources, including Aggregate Load Resources (ALRs):
(a)	Normal Ramp Rate curve;
(b)	Emergency Ramp Rate curve;
(c)	Maximum deployment time; and
(d)	Maximum weekly energy.
      (3)	Resource Parameters submitted by a Resource Entity must also include, for each of its ALRs, mapping between the ALR and the individually metered Loads, by Electric Service Identifier (ESI ID) or, in the case of a Non-Opt-In Entity (NOIE), equivalent unique meter identifier, comprising the ALR.
[NPRR1002:  Insert Section <IP_ADDRESS> below upon system implementation:]
<IP_ADDRESS>	 Energy Storage Resource Parameters
(1)	Resource Parameters for an ESR that may be modified, with documented reason for change, by the QSE for immediate use upon ERCOT validation include:
      (a)	Normal Ramp Rate curve; and
      (b)	Emergency Ramp Rate curve.
3.7.2	Changes in Resource Parameters with Operational Impacts
      (1)	The QSE representing each Resource shall have the responsibility to submit changes to Resource Parameters for those Resource Parameters related to the Current Operating Plan (COP), as described in Section 3.9, Current Operating Plan (COP), and to Real-Time operations as described in Section 6, Adjustment Period and Real-Time Operations.  If the QSE cancels a Resource Parameter submission, ERCOT will use as a default the Resource Parameter that is registered in the Network Operations Model.
3.7.3	Resource Parameter Validation
      (1)	ERCOT shall verify that changes to Resource Parameters submitted by the QSE representing the Resource comply with the Resource Registration Glossary.  If a Resource Parameter is determined to be invalid, then ERCOT shall reject it and provide written notice to the QSE representing the Resource of the reason for the rejection.
3.8	Special Considerations for Split Generation Meters, Combined Cycle Generation Resources, Quick Start Generation Resources, Hydro Generation Resources, Energy Storage Resources, Distribution Generation Resources, and Distribution Energy Storage Resources
[NPRR1026:  Replace Section 3.8 above with the following upon system implementation:]
3.8	Special Considerations
 3.8.1	Split Generation Resources
(1)	When a generation meter is split, as provided for in Section <IP_ADDRESS>, Generation Resource Meter Splitting, two or more independent Generation Resources must be created in the ERCOT Network Operations Model according to Section <IP_ADDRESS>, Modeling of Resources and Transmission Loads, to function in all respects as Split Generation Resources in ERCOT System operation.  A Combined Cycle Train may not be registered in ERCOT as a Split Generation Resource.  A Distribution Generation Resource (DGR) or Distribution Energy Storage Resource (DESR) may not be registered in ERCOT as a Split Generation Resource.
(2)	Each Qualified Scheduling Entity (QSE) representing a Split Generation Resource shall collect and shall submit to ERCOT the Resource Parameters defined under Section 3.7, Resource Parameters, for the Split Generation Resource it represents.  The parameters provided must be consistent with the parameters submitted by each other QSE that represents a Split Generation Resource from the same Generation Resource.  The parameters submitted for each Split Generation Resource for limits and ramp rates must be according to the capability of the Split Generation Resource represented by the QSE.  Startup and shutdown times, time to change status and number of starts must be identical for all the Split Generation Resources from the same Generation Resource submitted by each QSE.  ERCOT shall review data submitted by each QSE representing Split Generation Resources for consistency and notify each QSE of any errors.
(3)	Each Split Generation Resource may be represented by a different QSE.  The Resource Entities that own or control the Split Generation Resources from a single Generation Resource must designate a Master QSE.  Each QSE representing a Split Generation Resource must comply in all respects to the requirements of a Generation Resource specified under these Protocols.
(4)	The Master QSE shall:
            (a)	Serve as the Single Point of Contact for the Generation Resource, as required by Section <IP_ADDRESS>, Single Point of Contact;
            (b)	Provide real-time telemetry for the total Generation Resource, as specified in Section <IP_ADDRESS>, Operational Data Requirements; and
            (c)	Receive Verbal Dispatch Instructions (VDIs) from ERCOT, as specified in Section <IP_ADDRESS>, Dispatch Procedures.
(5)	Each QSE is responsible for representing its Split Generation Resource in its Current Operating Plan (COP).  During the Reliability Unit Commitment (RUC) Study Periods, any conflict in the Resource Status of a Split Generation Resource in the COP is resolved according to the following:
(a)	If a Split Generation Resource has a Resource Status of OUT for any hour in the COP, then any other QSEs' COP entries for their Split Generation Resources from the same Generation Resource are also considered unavailable for the hour;
            (b)	If the QSEs for all Split Generation Resources from the same Generation Resource have submitted a COP and at least one of the QSEs has an On-Line Resource Status in a given hour, then the status for all Split Generation Resources for the Generation Resource is considered to be On-Line for that hour, except if any of the QSEs has indicated in the COP a Resource Status of OUT.
(6)	Each QSE representing a Split Generation Resource shall update its individual Resource Status appropriately.
(7)	Each QSE representing a Split Generation Resource may independently submit Energy Offer Curves and Three-Part Supply Offers.  ERCOT shall treat each Split Generation Resource offer as a separate offer, except that all Split Generation Resources in a single Generation Resource must be committed or decommitted together.
[NPRR1007:  Replace paragraph (7) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project:]
(7)	Each QSE representing a Split Generation Resource may independently submit Energy Offer Curves, Ancillary Service Offers, and Three-Part Supply Offers.  ERCOT shall treat each Split Generation Resource offer as a separate offer, except that all Split Generation Resources in a single Generation Resource must be committed or decommitted together.
(8)	Each QSE submitting verifiable cost data to ERCOT shall coordinate among all owners of a single Generation Resource to provide individual Split Generation Resource data consistent with the total verifiable cost of the entire Generation Resource.  ERCOT may compare the total verifiable costs with other similarly situated Generation Resources to determine the reasonability of the cost.
3.8.2	Combined Cycle Generation Resources
(1)	ERCOT shall assign a logical Resource Node for use in the Day-Ahead Market (DAM), RUC, Supplemental Ancillary Services Market (SASM), Security-Constrained Economic Dispatch (SCED) and Load Frequency Control (LFC) to each registered Combined Cycle Train.  Each Combined Cycle Generation Resource registered in the Combined Cycle Train will be mapped to the Combined Cycle Train logical Resource Node for the purposes of evaluating and settling each Combined Cycle Generation Resource's Three-Part Supply Offer and Ancillary Service Offer in the DAM, RUC and SCED.  Each generation unit identified in the Combined Cycle Train registration for a Combined Cycle Generation Resource configuration will be mapped to its designated Resource Node as determined in accordance with these Protocols and the Other Binding Document titled "Procedure for Identifying Resource Nodes."
[NPRR1007:  Replace paragraph (1) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project:]
(1)	ERCOT shall assign a logical Resource Node for use in the Day-Ahead Market (DAM), RUC, Security-Constrained Economic Dispatch (SCED) and Load Frequency Control (LFC) to each registered Combined Cycle Train.  Each Combined Cycle Generation Resource registered in the Combined Cycle Train will be mapped to the Combined Cycle Train logical Resource Node for the purposes of evaluating and settling each Combined Cycle Generation Resource's Three-Part Supply Offer and Ancillary Service Offer in the DAM, RUC and SCED.  Each generation unit identified in the Combined Cycle Train registration for a Combined Cycle Generation Resource configuration will be mapped to its designated Resource Node as determined in accordance with these Protocols and the Other Binding Document titled "Procedure for Identifying Resource Nodes."
(2)	If any of the generation units, designated in the Combined Cycle Train registration as a primary generation unit in a Combined Cycle Generation Resource, is isolated from the ERCOT Transmission Grid because of a transmission Outage reported in the Outage Scheduler, the DAM and RUC applications shall select an alternate generation unit for use in the application.
(3)	Three-Part Supply Offers submitted for a Combined Cycle Generation Resource will be modeled as High Reasonability Limit (HRL)-weighted injections at the Resource Connectivity Nodes of the associated Generation Resources.  ERCOT shall use the logical Resource Node to settle these offers.
(4)	In the DAM and RUC, ERCOT shall model the energy injection from each generation unit registered to the Combine Cycle Generation Resource designated in a Three-Part Supply Offer as follows:
(a)	The energy injection for each generation unit registered in the Combined Cycle Generation Resource designated in a Three-Part Supply Offer shall be the offered energy injection for the selected price point on the Three-Part Supply Offer's Energy Offer Curve times a weight factor as determined in paragraph (4)(b) below.
(b)	The weight factor for each generation unit registered in a Combined Cycle Generation Resource shall be the generation unit's HRL, as specified in the Resource Registration data provided to ERCOT pursuant to Planning Guide Section 6.8.2, Resource Registration Process, divided by the total of all HRL values for the generation units registered in the designated Combined Cycle Generation Resource.
(5)	In the Network Operations Network Models used in the DAM, RUC and SCED applications, each generation unit identified in the Combined Cycle Train registration must be modeled at its Resource Connectivity Node.
(6)	For Ancillary Services offered and provided from Combined Cycle Generation Resources, ERCOT shall apply, without exception, the same rules and requirements specified in these Protocols for the DAM, RUC and Adjustment Period and Real-Time markets that apply to Ancillary Services provided from any other Generation Resources.
(a)	ERCOT systems shall determine the High and Low Ancillary Service Limits (HASL and LASL) for a Combined Cycle Generation Resource as follows:
(i)	In Real Time, relative to the telemetered High Sustained Limit (HSL) for the Combined Cycle Generation Resource, or
(ii)	During the DAM and RUC study periods, relative to the HSL in the COP.
            (b)	The QSE shall assure that the Combined Cycle Generation Resource designated as On-Line through telemetry or in the COP can meet its Ancillary Service Resource Responsibility.
[NPRR1007:  Replace paragraph (6) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project:]
(6)	For Ancillary Services offered and provided from Combined Cycle Generation Resources, ERCOT shall apply, without exception, the same rules and requirements specified in these Protocols for the DAM, RUC and Adjustment Period and Real-Time markets that apply to Ancillary Services provided from any other Generation Resources.
      (a)	ERCOT systems shall determine the operating limits for a Combined Cycle Generation Resource as follows:
            (i)	In Real-Time, relative to the telemetered capacity limits, ramp rates, and Ancillary Service capabilities for the Combined Cycle Generation Resource;
            (ii)	During the DAM study period, relative to the HSL in the COP; or
            (iii) 	During the RUC Study Period, relative to the capacity limits and Ancillary Service capabilities in the COP.
3.8.3	Quick Start Generation Resources
(1)	The QSE for a Quick Start Generation Resource (QSGR) that is available for deployment by SCED shall set the COP Resource Status to OFFQS, and the COP Low Sustained Limit (LSL) and COP HSL values to the expected sustainable LSL and HSL for the QSGR for the hour.  If the QSGR is providing Non-Spinning Reserve (Non-Spin) service, then the Ancillary Service Resource Responsibility for Non-Spin shall be set to the Resource's QSE-assigned Non-Spin responsibility in the COP.
[NPRR863 and NPRR1007:  Replace applicable portions of paragraph (1) above with the following upon system implementation for NPRR863; or upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007:]
(1)	The QSE for a Quick Start Generation Resource (QSGR) that is available for deployment by SCED and awarding of ERCOT Contingency Reserve Service (ECRS) and Non-Spinning Reserve (Non-Spin), if qualified and capable, shall set the COP Resource Status to OFFQS, and the COP Low Sustained Limit (LSL) and COP HSL values to the expected sustainable LSL and HSL for the QSGR for the hour.
(2)	The QSGR that is available for deployment by SCED shall telemeter a Resource Status of OFFQS and a LSL of zero prior to receiving a deployment instruction from SCED.  This status is necessary in order for SCED to recognize that the Resource can be Dispatched.  The status of the breaker shall be open and the output of the Resource shall be zero in order for the State Estimator to correctly assess the state of the system.  After being deployed for energy from SCED, the Resource shall telemeter an LSL equal to or less than the Resource's actual output until the Resource has ramped to its physical LSL.  After reaching its physical LSL, the QSGR shall telemeter an LSL that reflects its physical LSL.  The QSGR that is providing Off-Line Non-Spin shall always telemeter an Ancillary Service Resource Responsibility for Non-Spin to reflect the Resource's Non-Spin obligation and shall always telemeter an Ancillary Service Schedule for Non-Spin of zero to make the capacity available for SCED.
[NPRR1007:  Replace paragraph (2) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project:]
(2)	The QSGR that is available for deployment by SCED and awarding of ECRS and Non-Spin, if qualified and capable, shall telemeter a Resource Status of OFFQS and a LSL of zero prior to receiving a deployment instruction from SCED.  This status is necessary in order for SCED to recognize that the Resource can be Dispatched and/or awarded ECRS and Non-Spin.  The status of the breaker shall be open and the output of the Resource shall be zero in order for the State Estimator to correctly assess the state of the system.  After being deployed for energy from SCED, the Resource shall telemeter an LSL equal to or less than the Resource's actual output until the Resource has ramped to its physical LSL.  After reaching its physical LSL, the QSGR shall telemeter an LSL that reflects its physical LSL.
(3)	A QSGR with a telemeter breaker status of open and a telemeter Resource Status OFFQS shall not provide Regulation Service or Responsive Reserve (RRS).
(4)	ERCOT shall adjust the QSGR's Mitigated Offer Cap (MOC) curve as described in Section <IP_ADDRESS>.1, Mitigated Offer Cap.
(5)	For a QSGR that is physically Off-Line, the Resource Entity shall submit a Normal Ramp Rate curve and Emergency Ramp Rate curve indicating QSGR's ability to reach its ten-minute tested output from zero output in five minutes.  This is necessary to prevent SCED from deploying multiple QSGRs due to ramp limitation in the first five minutes after being Dispatched by SCED.  QSGRs shall be exempt from Base Point Deviation Charges as described in Section <IP_ADDRESS>, Resources Exempt from Deviation Charges.
[NPRR1007:  Replace paragraph (5) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project:]
(5)	For a QSGR that is physically Off-Line, the Resource Entity shall submit a Normal Ramp Rate curve and Emergency Ramp Rate curve indicating QSGR's ability to reach its ten-minute tested output from zero output in five minutes.  This is necessary to prevent SCED from deploying multiple QSGRs due to ramp limitation in the first five minutes after being Dispatched by SCED.  QSGRs shall be exempt from Set Point Deviation Charges as described in Section <IP_ADDRESS>, Resources Exempt from Deviation Charges.
(6)	Any hour in which the QSE for the QSGR has shown the Resource as available for SCED Dispatch as described in this Section 3.8.3 is considered a QSE-Committed Interval.
(7)	QSEs must submit and maintain an Energy Offer Curve for their QSGRs for all hours in which the COP Resource Status is submitted as OFFQS.  If a valid Energy Offer Curve or an Output Schedule does not exist for any QSGR for which a Resource Status of OFFQS is telemetered at the end of the Adjustment Period, then ERCOT shall notify the QSE and set the Output Schedule equal to the then-current telemetered output of the Resource until an Output Schedule or Energy Offer Curve is submitted in a subsequent Adjustment Period.  For use as SCED inputs, ERCOT shall create proxy Energy Offer Curves for the Resource as described in paragraph (4) of Section <IP_ADDRESS>, Security Constrained Economic Dispatch.
(8)	Other than for the potential decommitment of a QSGR as described in Section <IP_ADDRESS>, Quick Start Generation Resource Decommitment Decision Process, following a SCED QSGR deployment, the QSGR is expected to follow the SCED Base Points.
<IP_ADDRESS>	Quick Start Generation Resource Decommitment Decision Process
(1)	For purposes of determining whether SCED needs a QSGR to continue to generate per paragraph (3) of Section 6.6.9, Emergency Operations Settlement, the QSE representing the QSGR shall telemeter an LSL of zero for at least one but no more than two non-consecutive SCED executions in each Operating Hour during which the QSGR is operating with a SCED Base Point equal to its registered LSL and shall telemeter Normal and Emergency Ramp Rates indicating that the QSGR can be Dispatched to zero output in a single SCED interval.
            (a)	If the SCED issued Base Point for the QSGR is non-zero in the interval where a zero LSL has been telemetered by the QSE, then the QSGR is deemed needed by SCED and the QSE shall immediately resume telemetering an LSL equal to the physical LSL and continue to operate the unit following subsequent Base Points.
            (b)	If the Base Point is zero, then the QSE will decommit the QSGR using normal operating practices.
            (c)	If at any point during the period in which the QSGR is in SHUTDOWN mode, the QSGR Locational Marginal Price (LMP) is greater than or equal to the Energy Offer Curve price, capped per Section <IP_ADDRESS>.1, Mitigated Offer Cap, the QSE may reverse the decommitment process, if possible and make the QSGR available for SCED following normal operating practices.
3.8.4	Generation Resources Operating in Synchronous Condenser Fast-Response Mode
(1)	A QSE is considered to have performed for the amount of its RRS obligation for the MW amount provided by a Generation Resource operating in synchronous condenser fast-response mode and triggered by an under-frequency relay device at the frequency set point specified in paragraph (3)(c) of Section 3.18, Resource Limits in Providing Ancillary Service, without corresponding RRS deployment by ERCOT.  This provision applies only for the duration when RRS MW is deployed by automatic under-frequency relay action.
3.8.5	Energy Storage Resources
(1)	The Resource Entity and QSE representing an Energy Storage Resource (ESR) which is jointly registered with ERCOT as a Generation Resource and a Controllable Load Resource, pursuant to paragraph (6) of Section 16.5, Registration of a Resource Entity, are responsible for following all requirements in these Protocols associated with Generation Resources and Controllable Load Resources.
[NPRR1002:  Replace paragraph (1) above with the following upon system implementation:]
(1)	For the purposes of all ERCOT Protocols and Other Binding Documents, all requirements that apply to Generation Resources and Controllable Load Resources shall be understood to apply to Energy Storage Resources (ESRs) to the same extent, except where the Protocols explicitly provide otherwise.
(2)	A QSE representing an ESR may update the telemetered HSL and/or Maximum Power Consumption (MPC) for the ESR in Real-Time to ensure the ability to meet the ESR's full Ancillary Service Resource Responsibility for the current Operating Hour.  This provision only applies when the MOC for an ESR is set at the System-Wide Offer Cap (SWCAP) pursuant to paragraph (1)(b) of Section <IP_ADDRESS>.1, Mitigated Offer Cap.
[NPRR1075:  Delete paragraph (2) above upon system implementation of the Real-Time Co-Optimization (RTC) project.]
(3)	A QSE representing an ESR may update the telemetered HSL and/or MPC for the ESR in Real-Time to reflect state of charge limitations.
[NPRR1075:  Replace paragraph (3) above with the following upon system implementation of NPRR1014:]
(3)	A QSE representing an ESR may update the telemetered HSL and/or LSL for the ESR in Real-Time to reflect state of charge limitations.
(4)	A QSE representing an ESR co-located with a Generation Resource may reduce the telemetered MPC of the Controllable Load Resource modeled to represent the charging side of the ESR when self-charging using output from the Generation Resource.  Such reduction in MPC shall be equal to the MW level of self-charge.
[NPRR1075:  Replace paragraph (4) above with the following upon system implementation of NPRR1014:]
(4)	A QSE representing an ESR co-located with a Generation Resource may update the telemetered LSL of the ESR when self-charging (using output from the Generation Resource).  The updated LSL shall be equal to the MW level of self-charge.
3.8.6	Distribution Generation Resources (DGRs) and Distribution Energy Storage Resources (DESRs)
(1)	As a condition for the interconnection of a DGR or DESR, the affected Resource Entity, after consultation with the relevant Distribution Service Provider (DSP), shall provide documentation from the DSP to ERCOT stating that the interconnecting distribution circuit will not be disconnected as part of an Energy Emergency Alert (EEA) Level 3, an under-frequency Load shedding event, or an under-voltage Load shedding event, unless required for DSP local system maintenance or during a DSP local system emergency.
      (a)	If a DSP subsequently determines that any circuit to which a DGR or DESR is interconnected will need to be disconnected during these Load shedding events, or that a DGR or DESR will need to be moved to a circuit that will be disconnected during these Load shedding events:
            (i)	The DSP shall promptly notify the designated contact for the DGR or DESR;
            (ii)	The Resource Entity shall promptly notify ERCOT of this fact via the Resource Registration process; and
            (iii)	The DGR or DESR will immediately be disqualified from offering to provide any Ancillary Service.
      (b)	Upon receiving notification from the DSP that the DGR or DESR is no longer subject to disconnection during any of these Load shedding events, and that no known system limitations or changes have occurred that would inhibit the DGR or DESR from complying with Ancillary Service performance requirements, the Resource Entity for the DGR or DESR shall notify ERCOT of this fact via the Resource Registration process and will, at that time, be eligible to offer to provide Ancillary Services if the Resource is otherwise qualified to do so.
(2)	For a proposed conversion of an existing Settlement Only Distribution Generator (SODG) to a DGR or DESR, the interconnecting DSP will evaluate the proposed conversion and will determine whether it is electrically and operationally feasible.  If the interconnecting DSP determines that the conversion is not electrically or operationally feasible, the DSP may disallow the conversion.
[NPRR995:  Replace paragraph (2) above with the following upon system implementation:]
(2)	For a proposed conversion of an existing Settlement Only Distribution Generator (SODG) to a DGR or for a proposed conversion of an existing Settlement Only Distribution Energy Storage System (SODESS) to a DESR, the interconnecting DSP will evaluate the proposed conversion and will determine whether it is electrically and operationally feasible.  If the interconnecting DSP determines that the conversion is not electrically or operationally feasible, the DSP may disallow the conversion.
(3)	The Resource Node for a DGR or DESR shall be fixed at a single Electrical Bus in the ERCOT Network Operations Model.
      (a)	If a DSP determines that a topology change has altered, or is expected to alter, the electrical path connecting the DGR or DESR to the ERCOT Transmission Grid for a period longer than 60 days:
            (i)	The DSP shall promptly notify the interconnecting Transmission Service Provider (TSP) and the designated contact for the DGR or DESR, and the interconnecting TSP shall notify ERCOT; and
            (ii)	The Resource Entity shall submit a change request to ERCOT via the Resource Registration process.

[NPRR1026 and NPRR1077:  Insert applicable portions of Section 3.8.7 below upon system implementation:]
3.8.7	Self-Limiting Facility
(1)	A Resource Entity or Interconnecting Entity (IE) for a Self-Limiting Facility may establish a MW Injection or MW Withdrawal limit by submitting an attestation in a form designated by ERCOT through the Resource Registration process.  The Resource Entity or IE shall simultaneously provide a copy of the attestation to the interconnecting Transmission and/or Distribution Service Provider (TDSP).  All registered generators or Energy Storage Systems (ESSs) within a Self-Limiting Facility shall be represented by a single Resource Entity and a single QSE.
(2)	A Self-Limiting Facility shall not inject or withdraw power in excess of its established MW Injection limit or its established MW Withdrawal limit.
(3)	On a monthly basis, ERCOT will report to the Reliability Monitor and IMM any instance where a Self-Limiting Facility's actual MW Injections exceeded the MW Injection limit or where actual MW Withdrawals exceeded the MW Withdrawal limit established in the Resource Registration data for the Self-Limiting Facility, based on the telemetry of the injection and withdrawal values provided by the QSE for the registered generator or ESS in the Self-Limiting Facility, as described in Section 3.9.1, Current Operating Plan (COP) Criteria, and in Section <IP_ADDRESS>, Operational Data Requirements, or based on the meter data at the Point of Interconnection (POI) or Point of Common Coupling (POCC) for the Self-Limiting Facility.
(4)	If requested by ERCOT, the relevant QSE shall provide meter data to confirm whether the established limits for a Self-Limiting Facility were violated.
(5)	If ERCOT determines that a Self-Limiting Facility connected at transmission voltage has exceeded either its MW Injection limit or its MW Withdrawal limit established in the Resource Registration data by more than the greater of 5 MW or 3% of the limit, the Self-Limiting Facility shall submit a new generation interconnection request based on the installed MW capacity of the individual Resource(s) and shall deregister as a Self-Limiting Facility at the completion of the generation interconnection process.  The Self-Limiting Facility shall be subject to the established MW Injection limit and any established MW Withdrawal limit until the generation interconnection process has been completed.
(6)	A Distribution Service Provider (DSP) may limit injections and withdrawals from any Generation Resource, Settlement Only Generator (SOG), or ESR based on Resource Registration data and the interconnection agreement between the DSP and the IE or Resource Entity.  In that case, the IE or Resource Entity shall submit the attestation required by paragraph (1) above, and shall be considered a Self-Limiting Facility.
(7)	If ERCOT determines that a Self-Limiting Facility connected at distribution voltage has exceeded either its MW Injection limit or its MW Withdrawal limit established in the Resource Registration data, the Self-Limiting Facility shall submit a new generation interconnection request based on the installed MW capacity of the individual Resource(s) and shall be deregistered as a Self-Limiting Facility at the completion of the generation interconnection process.  The Self-Limiting Facility shall be subject to any MW Injection or MW Withdrawal limit until the generation interconnection process has been completed.
(8)	The interconnecting TDSP, at its sole discretion, may use relaying to ensure a Self-Limiting Facility does not inject or withdraw energy in excess of its MW Injection or MW Withdrawal limits in order to protect the TDSP's limiting element(s).

[NPRR1029 and NPRR1111:  Insert applicable portions of Section 3.8.8 below upon system implementation for NPRR1029; or upon system implementation of SCR819 for NPRR1111:]
3.8.8	DC-Coupled Resources
(1)	A DC-Coupled Resource shall be treated in the same manner as an Energy Storage Resource (ESR) for the purposes of determining Set Point Deviation Charges, as described in Section 6.6.5, Set Point Deviation Charge, and Energy Storage Resource Energy Deployment Performance (ESREDP), as described in Section <IP_ADDRESS>.1, Regulation Service and Generation Resource/Controllable Load Resource/Energy Storage Resource Energy Deployment Performance, under one of the following conditions:
      (a)	The Resource was awarded Ancillary Service;
      (b)	The Resource's instantaneous MW Injection or MW Withdrawal includes non-zero MW from the ESS component of the DC-Coupled Resource; or
      (c)	The Resource's telemetered HSL or LSL includes the ESS capability.
(2)	At all other times, a DC-Coupled Resource shall be treated in the same manner as an IRR for the purposes of determining Set Point Deviation Charges, as described in Section 6.6.5, and ESREDP, as described in Section <IP_ADDRESS>.1.
(3)	A QSE representing a DC-Coupled Resource that does not meet any of the conditions in paragraph (1) above:
      (a)	Shall set the Resource's telemetered HSL equal to the current net output capability of the intermittent renewable generation component of the DC-Coupled Resource; and
      (b)	Shall set the Resource's output at or below the SCED Base Point telemetered by ERCOT if the Resource receives a flag indicating that SCED has dispatched it below the Resource's HDL used by SCED or that it has been instructed not to exceed its Base Point.
3.9	Current Operating Plan (COP)
(1)	Each Qualified Scheduling Entity (QSE) that represents a Resource must submit a Current Operating Plan (COP) under this Section.
(2)	ERCOT shall use the information provided in the COP to calculate the High Ancillary Service Limit (HASL) and Low Ancillary Service Limit (LASL) for each Resource for the Reliability Unit Commitment (RUC) processes.
[NPRR1007:  Replace paragraph (2) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project:]
(2)	ERCOT shall use the information provided in the COP to calculate operating limits and Ancillary Service capabilities for each Resource for the Reliability Unit Commitment (RUC) processes.
(3)	ERCOT shall monitor the accuracy of each QSE's COP as outlined in Section 8, Performance Monitoring.
(4)	A QSE must notify ERCOT that it plans to have a Resource On-Line by means of the COP using the Resource Status codes listed in paragraph (5)(b)(i) of Section 3.9.1, Current Operating Plan (COP) Criteria.  The QSE must show the Resource as On-Line with a Resource Status of ONRUC, indicating a RUC process committed the Resource for all RUC-Committed Intervals.  A QSE may only use a RUC-committed Resource during that Resource's RUC-Committed Interval to meet the QSE's Ancillary Service Supply Responsibility if the Resource has been committed by the RUC process to provide Ancillary Service.
(5)	To reflect changes to a Resource's capability, each QSE shall report by exception, changes to the COP for all hours after the Operating Period through the rest of the Operating Day.
(6)	When a QSE updates its COP to show changes in Resource Status, the QSE shall update for each On-Line Resource, either an Energy Offer Curve under Section 4.4.9, Energy Offers and Bids, or Output Schedule under Section 6.4.2, Output Schedules.
(7)	Each QSE, including QSEs representing Reliability Must-Run (RMR) Units, or Black Start Resources, shall submit a revised COP reflecting changes in Resource availability as soon as reasonably practicable, but in no event later than 60 minutes after the event that caused the change.
[NPRR1120:  Replace paragraph (7) above with the following upon system implementation:]
(7)	Each QSE, including QSEs representing Reliability Must-Run (RMR) Units, Firm Fuel Supply Service Resources (FFSSRs), or Black Start Resources, shall submit a revised COP reflecting changes in Resource availability as soon as reasonably practicable, but in no event later than 60 minutes after the event that caused the change.
(8)	Each QSE representing a Qualifying Facility (QF) must submit a Low Sustained Limit (LSL) that represents the minimum energy available, in MW, from the unit for economic dispatch based on the minimum stable steam delivery to the thermal host plus a justifiable reliability margin that accounts for changes in ambient conditions.
3.9.1	Current Operating Plan (COP) Criteria
(1)	Each QSE that represents a Resource must submit a COP to ERCOT that reflects expected operating conditions for each Resource for each hour in the next seven Operating Days.
(2)	Each QSE that represents a Resource shall update its COP reflecting changes in availability of any Resource as soon as reasonably practicable, but in no event later than 60 minutes after the event that caused the change.
(3)	The Resource capacity in a QSE's COP must be sufficient to supply the Ancillary Service Supply Responsibility of that QSE.
[NPRR1007, NPRR1014, and NPRR1029:  Replace applicable portions of paragraph (3) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029:]
(3)	Each QSE that represents a Resource shall update its COP to reflect the ability of the Resource to provide each Ancillary Service by product and sub-type.
(4)	Load Resource COP values may be adjusted to reflect Distribution Losses in accordance with Section <IP_ADDRESS>, General Capacity Testing Requirements.
(5)	A COP must include the following for each Resource represented by the QSE:
(a)	The name of the Resource;
(b)	The expected Resource Status:
(i)	Select one of the following for Generation Resources synchronized to the ERCOT System that best describes the Resource's status.  Unless otherwise provided below, these Resource Statuses are to be used for COP and/or Real-Time telemetry purposes, as appropriate.
(A)	ONRUC  -  On-Line and the hour is a RUC-Committed Hour;
(B)	ONREG  -  On-Line Resource with Energy Offer Curve providing Regulation Service;
[NPRR1007, NPRR1014, and NPRR1029:  Delete item (B) above upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029; and renumber accordingly.]
(C)	ON  -  On-Line Resource with Energy Offer Curve;
(D)	ONDSR  -  On-Line Dynamically Scheduled Resource (DSR);
[NPRR1000:  Delete item (D) above upon system implementation and renumber accordingly.]
(E)	ONOS  -  On-Line Resource with Output Schedule;
(F)	ONOSREG  -  On-Line Resource with Output Schedule providing Regulation Service;
[NPRR1007, NPRR1014, and NPRR1029:  Delete item (F) above upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029; and renumber accordingly.]
(G)	ONDSRREG  -  On-Line DSR providing Regulation Service;
[NPRR1000, NPRR1007, NPRR1014, and NPRR1029:  Delete item (G) above upon system implementation for NPRR1000, NPRR1014, or NPRR1029; or upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; and renumber accordingly.]
                  (H)	FRRSUP  -  Available for Dispatch of Fast Responding Regulation Service (FRRS).  This Resource Status is only to be used for Real-Time telemetry purposes;
[NPRR1007, NPRR1014, and NPRR1029:  Delete item (H) above upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 and NPRR1029; and renumber accordingly.]
(I)	ONTEST  -  On-Line blocked from Security-Constrained Economic Dispatch (SCED) for operations testing (while ONTEST, a Generation Resource may be shown on Outage in the Outage Scheduler);
(J)	ONEMR  -  On-Line EMR (available for commitment or dispatch only for ERCOT-declared Emergency Conditions; the QSE may appropriately set LSL and High Sustained Limit (HSL) to reflect operating limits);
(K)	ONRR  -  On-Line as a synchronous condenser providing Responsive Reserve (RRS) but unavailable for Dispatch by SCED and available for commitment by RUC;
[NPRR1007, NPRR1014, and NPRR1029:  Delete item (K) above upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029; and renumber accordingly.]

[NPRR863:  Insert paragraph (L) below upon system implementation and renumber accordingly:]
                  (L)	ONECRS  -  On-Line as a synchronous condenser providing ERCOT Contingency Response Service (ECRS) but unavailable for Dispatch by SCED and available for commitment by RUC;

[NPRR1007, NPRR1014, and NPRR1029:  Delete item (L) above upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029; and renumber accordingly.]
(L)	ONOPTOUT  -  On-Line and the hour is a RUC Buy-Back Hour;
(M)	SHUTDOWN  -  The Resource is On-Line and in a shutdown sequence, and has no Ancillary Service Obligations other than Off-Line Non-Spinning Reserve (Non-Spin) which the Resource will provide following the shutdown.  This Resource Status is only to be used for Real-Time telemetry purposes;
[NPRR1007, NPRR1014, and NPRR1029:  Replace paragraph (M) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029:]
                  (H)	SHUTDOWN  -  The Resource is On-Line and in a shutdown sequence, and is not eligible for an Ancillary Service award.  This Resource Status is only to be used for Real-Time telemetry purposes;
(N)	STARTUP  -  The Resource is On-Line and in a start-up sequence and has no Ancillary Service Obligations.  This Resource Status is only to be used for Real-Time telemetry purposes;
[NPRR1007, NPRR1014, and NPRR1029:  Replace paragraph (N) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029:]
                  (I)	STARTUP  -  The Resource is On-Line and in a start-up sequence and is not eligible for an Ancillary Service award, unless coming On-Line in response to a manual deployment of ERCOT Contingency Reserve Service (ECRS) or Non-Spinning Reserve (Non-Spin).  This Resource Status is only to be used for Real-Time telemetry purposes;
(O)	OFFQS  -  Off-Line but available for SCED deployment.  Only qualified Quick Start Generation Resources (QSGRs) may utilize this status; and
[NPRR1007, NPRR1014, and NPRR1029:  Replace paragraph (O) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029:]
                  (J)	OFFQS  -  Off-Line but available for SCED deployment and to provide ECRS and Non-Spin, if qualified and capable.  Only qualified Quick Start Generation Resources (QSGRs) may utilize this status;
(P)	ONFFRRRS  -  Available for Dispatch of RRS providing Fast Frequency Response (FFR) from Generation Resources.  This Resource Status is only to be used for Real-Time telemetry purposes;
[NPRR1015:  Replace paragraph (P) above with the following upon system implementation of NPRR863:]
                  (P)	ONFFRRRS  -  Available for Dispatch of RRS when providing Fast Frequency Response (FFR) from Generation Resources.  This Resource Status is only to be used for Real-Time telemetry purposes.  A Resource with this Resource Status may also be providing Ancillary Services other than FFR;

[NPRR1007, NPRR1014, and NPRR1029:  Delete item (P) above upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029; and renumber accordingly.]

[NPRR1007, NPRR1014, and NPRR1029:  Insert applicable portions of items (K) and (L) below upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029:]
                  (K)	ONSC  -  Resource is On-Line operating as a synchronous condenser and available to provide Responsive Reserve (RRS) and ECRS, if qualified and capable, and for commitment by RUC, but is unavailable for Dispatch by SCED.  For SCED, Resource Base Points will be set equal to the telemetered net real power of the Resource available at the time of the SCED execution; and
                  (L)	ONHOLD  -  Resource is On-Line but temporarily unavailable for Dispatch by SCED or Ancillary Service awards.  This Resource Status is only to be used for Real-Time telemetry purposes.  For SCED, Resource Base Points will be set equal to the telemetered net real power of the Resource available at the time of the SCED execution.
(ii)	Select one of the following for Off-Line Generation Resources not synchronized to the ERCOT System that best describes the Resource's status.  These Resource Statuses are to be used for COP and/or Real-Time telemetry purposes, as appropriate.
(A)	OUT  -  Off-Line and unavailable;
(B)	OFFNS  -  Off-Line but reserved for Non-Spin;
[NPRR1007, NPRR1014, and NPRR1029:  Delete item (B) above upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029; and renumber accordingly.]
(C)	OFF  -  Off-Line but available for commitment in the Day-Ahead Market (DAM) and RUC;
[NPRR1007, NPRR1014, and NPRR1029:  Replace item (C) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029:]
                  (B)	OFF  -  Off-Line but available for commitment in the Day-Ahead Market (DAM), RUC, and providing Non-Spin, if qualified and capable;
(D)	EMR  -  Available for commitment as a Resource contracted by ERCOT under Section 3.14.1, Reliability Must Run, or under paragraph (4) of Section <IP_ADDRESS>, ERCOT Control Area Authority, or available for commitment only for ERCOT-declared Emergency Condition events; the QSE may appropriately set LSL and HSL to reflect operating limits; and
(E)	EMRSWGR  -  Switchable Generation Resource (SWGR) operating in a non-ERCOT Control Area, or in the case of a Combined Cycle Train with one or more SWGRs, a configuration in which one or more of the physical units in that configuration are operating in a non-ERCOT Control Area; and
(iii)	Select one of the following for Load Resources.  Unless otherwise provided below, these Resource Statuses are to be used for COP and/or Real-Time telemetry purposes.
(A)	ONRGL  -  Available for Dispatch of Regulation Service by Load Frequency Control (LFC) and, for any remaining Dispatchable capacity, by SCED with a Real-Time Market (RTM) Energy Bid;
                  (B)	FRRSUP  -  Available for Dispatch of FRRS by LFC and not Dispatchable by SCED.  This Resource Status is only to be used for Real-Time telemetry purposes;
                  (C)	FRRSDN - Available for Dispatch of FRRS by LFC and not Dispatchable by SCED.  This Resource Status is only to be used for Real-Time telemetry purposes;
(D)	ONCLR  -  Available for Dispatch as a Controllable Load Resource by SCED with an RTM Energy Bid;
(E)	ONRL  -  Available for Dispatch of RRS or Non-Spin, excluding Controllable Load Resources;
[NPRR1007, NPRR1014, and NPRR1029:  Delete items (A)-(E) above upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029; and renumber accordingly.]

[NPRR863:  Insert paragraph (F) below upon system implementation and renumber accordingly:]
                  (F)	ONECL  -  Available for Dispatch of ECRS, excluding Controllable Load Resources;

[NPRR1007, NPRR1014, and NPRR1029:  Delete item (F) above upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029; and renumber accordingly.]
(F)	OUTL  -  Not available;
[NPRR863 and NPRR1015:  Insert applicable portions of paragraph (H) below upon system implementation of NPRR863:]
                  (H)	ONFFRRRSL  -  Available for Dispatch of RRS when providing FFR, excluding Controllable Load Resources. This Resource Status is only to be used for Real-Time telemetry purposes;

[NPRR1007, NPRR1014, and NPRR1029:  Delete item (H) above upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029.]

[NPRR1007, NPRR1014, NPRR1029:  Insert item (B) below upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029:]
                  (B)	ONL  -  On-Line and available for Dispatch by SCED or providing Ancillary Services.

[NPRR1014 or NPRR1029:  Insert applicable portions of paragraph (iv) below upon system implementation:]
            (iv)	Select one of the following for Energy Storage Resources (ESRs).  Unless otherwise provided below, these Resource Statuses are to be used for COP and Real-Time telemetry purposes:
                  (A)	ON  -  On-Line Resource with Energy Bid/Offer Curve;
                  (B)	ONOS  -  On-Line Resource with Output Schedule;
                  (C)	ONTEST  -  On-Line blocked from SCED for operations testing (while ONTEST, an Energy Storage Resource (ESR) may be shown on Outage in the Outage Scheduler);
                  (D)	ONEMR  -  On-Line EMR (available for commitment or dispatch only for ERCOT-declared Emergency Conditions; the QSE may appropriately set LSL and High Sustained Limit (HSL) to reflect operating limits);
                  (E)	ONHOLD  -  Resource is On-Line but temporarily unavailable for Dispatch by SCED or Ancillary Service awards.  ESRs shall not be discharging into or charging from the grid. This Resource Status is only to be used for Real-Time telemetry purposes; and
                  (F)	OUT  -  Off-Line and unavailable; and
(c)	The HSL;
                  (i)	For Load Resources other than Controllable Load Resources, the HSL should equal the expected power consumption;
[NPRR1014 and NPRR1029:  Insert applicable portions of paragraph (ii) below upon system implementation:]
            (ii)	For ESRs, the HSL may be negative;
(d)	The LSL;
                  (i)	For Load Resources other than Controllable Load Resources, the LSL should equal the expected Low Power Consumption (LPC);
[NPRR1014 and NPRR1029:  Insert applicable portions of paragraph (ii) below upon system implementation:]
            (ii)	For ESRs, the LSL may be positive;
(e)	The High Emergency Limit (HEL);
(f)	The Low Emergency Limit (LEL); and
(g)	Ancillary Service Resource Responsibility capacity in MW for:
[NPRR1007, NPRR1014, and NPRR1029:  Replace applicable portions of item (g) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029:]
      (g)	Ancillary Service capability in MW for each product and sub-type.
(i)	Regulation Up (Reg-Up);
(ii)	Regulation Down (Reg-Down);
(iii)	RRS; and
[NPRR863:  Insert paragraph (iv) below upon system implementation and renumber accordingly:]
(iv)	ECRS; and
(iv)	Non-Spin.
[NPRR1007, NPRR1014, and NPRR1029:  Delete items (i)-(iv) above upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029.]
(6)	For Combined Cycle Generation Resources, the above items are required for each operating configuration.  In each hour only one Combined Cycle Generation Resource in a Combined Cycle Train may be assigned one of the On-Line Resource Status codes described above.
(a)	During a RUC study period, if a QSE's COP reports multiple Combined Cycle Generation Resources in a Combined Cycle Train to be On-Line for any hour, then until the QSE corrects its COP, the On-Line Combined Cycle Generation Resource with the largest HSL is considered to be On-Line and all other Combined Cycle Generation Resources in the Combined Cycle Train are considered to be Off-Line.  Furthermore, until the QSE corrects its COP, the Off-Line Combined Cycle Generation Resources as designated through the application of this process are ineligible for RUC commitment or de-commitment Dispatch Instructions.
(b)	For any hour in which QSE-submitted COP entries are used to determine the initial state of a Combined Cycle Generation Resource for a DAM or Day-Ahead Reliability Unit Commitment (DRUC) study and the COP shows multiple Combined Cycle Generation Resources in a Combined Cycle Train to be in an On-line Resource Status, then until the QSE corrects its COP, the On-Line Combined Cycle Generation Resource that has been On-Line for the longest time from the last recorded start by ERCOT systems, regardless of the reason for the start, combined with the COP Resource Status for the remaining hours of the current Operating Day, is considered to be On-Line at the start of the DRUC study period and all other COP-designated Combined Cycle Generation Resources in the Combined Cycle Train are considered to be Off-Line.
(c)	ERCOT systems shall allow only one Combined Cycle Generation Resource in a Combined Cycle Train to offer Off-Line Non-Spin in the DAM or Supplemental Ancillary Services Market (SASM).
[NPRR1007, NPRR1014, and NPRR1029:  Replace paragraph (c) above with the following upon system implementation of the Real-Time Co-Optimization (RTC) project for NPRR1007; or upon system implementation for NPRR1014 or NPRR1029:]
      (c)	ERCOT systems shall allow only one Combined Cycle Generation Resource in a Combined Cycle Train to offer Off-Line Non-Spin in the DAM or SCED.
(i)	If there are multiple Non-Spin offers from different Combined Cycle Generation Resources in a Combined Cycle Train, then prior to execution of the DAM, ERCOT shall select the Non-Spin offer from the Combined Cycle Generation Resource with the highest HSL for consideration in the DAM and ignore the other offers.
(ii)	Combined Cycle Generation Resources offering Off-Line Non-Spin must be able to transition from the shutdown state to the offered Combined Cycle Generation Resource On-Line state and be capable of ramping to the full amount of the Non-Spin offered.
            (d)	The DAM and RUC shall honor the registered hot, intermediate or cold Startup Costs for each Combined Cycle Generation Resource registered in a Combined Cycle Train when determining the transition costs for a Combined Cycle Generation Resource.  In the DAM and RUC, the Startup Cost for a Combined Cycle Generation Resource shall be determined by the positive transition cost from the On-Line Combined Cycle Generation Resource within the Combine Cycle Train or from a shutdown condition, whichever ERCOT determines to be appropriate.
(7)	ERCOT may accept COPs only from QSEs.
(8)	For the first 168 hours of the COP, ERCOT will update the HSL values for Wind-powered Generation Resources (WGRs) with the most recently updated Short-Term Wind Power Forecast (STWPF), and the HSL values for PhotoVoltaic Generation Resources (PVGRs) with the most recently updated Short-Term PhotoVoltaic Power Forecast (STPPF).  ERCOT will notify the QSE via an Extensible Markup Language (XML) message each time COP HSL values are updated with the forecast values.  A QSE representing a WGR may override the STWPF HSL value but must submit an HSL value that is less than or equal to the amount for that Resource from the most recent STWPF provided by ERCOT; a QSE representing a PVGR may override the STPPF HSL value but must submit an HSL value that is less than or equal to the amount for that Resource from the most recent STPPF provided by ERCOT.
[NPRR1029:  Replace paragraph (8) above with the following upon system implementation:]
(8)	For the first 168 hours of the COP, ERCOT will update the HSL values for Wind-powered Generation Resources (WGRs) with the most recently updated Short-Term Wind Power Forecast (STWPF), and the HSL values for PhotoVoltaic Generation Resources (PVGRs) with the most recently updated Short-Term PhotoVoltaic Power Forecast (STPPF).  A QSE representing a DC-Coupled Resource shall provide the capacity value of the Energy Storage System (ESS) that is included in the HSL of the DC-Coupled Resource, and ERCOT will update the DC-Coupled Resource's HSL with the sum of the forecasts of the intermittent renewable generation component and the QSE-submitted value for the ESS component.  ERCOT will notify the QSE via an Extensible Markup Language (XML) message each time COP HSL values are updated with the forecast values.  A QSE representing a WGR may override the STWPF HSL value but must submit an HSL value that is less than or equal to the amount for that Resource from the most recent STWPF provided by ERCOT; a QSE representing a PVGR may override the STPPF HSL value but must submit an HSL value that is less than or equal to the amount for that Resource from the most recent STPPF provided by ERCOT.  A QSE representing a DC-Coupled Resource may override the COP HSL value with a value that is lower than the ERCOT-populated value, and may override with a value that is higher than the ERCOT-populated value if the ESS component of the DC-Coupled Resource can support the higher value.
(9)	A QSE representing a Generation Resource that is not actively providing Ancillary Services or is providing Off-Line Non-Spin that the Resource will provide following the shutdown, may only use a Resource Status of SHUTDOWN to indicate to ERCOT through telemetry that the Resource is operating in a shutdown sequence or a Resource Status of ONTEST to indicate in the COP and through telemetry that the Generation Resource is performing a test of its operations either manually dispatched by the QSE or by ERCOT as part of the test.  A QSE representing a Generation Resource that is not actively providing Ancillary Services may only use a Resource Status of STARTUP to indicate to ERCOT through telemetry that the Resource is operating in a start-up sequence requiring manual control and is not available for Dispatch.
(10)	If a QSE has not submitted a valid COP for any Generation Resource for any hour in the DAM or RUC Study Period, then the Generation Resource is considered to have a Resource Status as OUT thus not available for DAM awards or RUC commitments for those hours.
(11)	If a COP is not available for any Resource for any hour from the current hour to the start of the DAM period or RUC study, then the Resource Status for those hours are considered equal to the last known Resource Status from a previous hour's COP or from telemetry as appropriate for that Resource.
(12)	A QSE representing a Resource may only use the Resource Status code of EMR for a Resource whose operation would have impacts that cannot be monetized and reflected through the Resource's Energy Offer Curve or recovered through the RUC make-whole process or if the Resource has been contracted by ERCOT under Section 3.14.1 or under paragraph (4) of Section <IP_ADDRESS>.  If ERCOT chooses to commit an Off-Line unit with EMR Resource Status that has been contracted by ERCOT under Section 3.14.1 or under paragraph (4) of Section <IP_ADDRESS>, the QSE shall change its Resource Status to ONRUC.  Otherwise, the QSE shall change its Resource Status to ONEMR.
(13)     A QSE representing a Resource may use the Resource Status code of ONEMR for a        Resource that is:
            (a)	On-Line, but for equipment problems it must be held at its current output level until repair and/or replacement of equipment can be accomplished; or
            (b)	A hydro unit.
(14)	A QSE operating a Resource with a Resource Status code of ONEMR may set the HSL and LSL of the unit to be equal to ensure that SCED does not send Base Points that would move the unit.
(15)	A QSE representing a Resource may use the Resource Status code of EMRSWGR only for an SWGR.
[NPRR1026:  Insert paragraph (16) below upon system implementation:]
(16)	A QSE representing a Self-Limiting Facility must ensure that the sum of the COP HSL/LSL and the sum of the telemetered HSL/LSL submitted for each Resource within the Self-Limiting Facility do not exceed either the limit on MW Injection or the limit on the MW Withdrawal established for the Self-Limiting Facility.

[NPRR1029:  Insert paragraph (16) below upon system implementation:]
(16)	A QSE representing a DC-Coupled Resource shall not submit an HSL that exceeds the inverter rating or the sum of the nameplate ratings of the generation component(s) of the Resource.
3.9.2	Current Operating Plan Validation
(1)	ERCOT shall verify that each COP, on its submission, complies with the criteria described in Section 3.9.1, Current Operating Plan (COP) Criteria.  ERCOT shall notify the QSE by means of the Messaging System if the QSE's COP fails to comply with the criteria described in Section 3.9.1 and this Section 3.9.2 for any reason.  The QSE must then resubmit the COP within the appropriate market timeline.
(2)	ERCOT may reject a COP that does not meet the criteria described in Section 3.9.1.
(3)	If a Resource is designated in the COP to provide Ancillary Service, then ERCOT shall verify that the COP complies with Section 3.16, Standards for Determining Ancillary Service Quantities.  The Ancillary Service Supply Responsibilities as indicated in the Ancillary Service Resource Responsibility submitted immediately before the end of the Adjustment Period are physically binding commitments for each QSE for the corresponding Operating Period.
(4)	ERCOT shall notify the QSE if the sum of the Ancillary Service capacity designated in the COP for each hour, by service type, is less than the QSE's Ancillary Service Supply Responsibility for each service type for that hour.  If the QSE does not correct the deficiency within one hour after receiving the notice from ERCOT, then ERCOT shall follow the procedures outlined in Section <IP_ADDRESS>, Evaluation and Maintenance of Ancillary Service Capacity Sufficiency.
(5)	A QSE may change Ancillary Service Resource designations by changing its COP, subject to Section <IP_ADDRESS>.
(6)	If ERCOT determines that it needs more Ancillary Service during the Adjustment Period, then the QSE's allocated portion of the additional Ancillary Service may be self-arranged.
[NPRR1007:  Delete paragraphs (3)-(6) above upon system implementation of the Real-Time Co-Optimization (RTC) project and renumber accordingly.]
(7)	ERCOT systems must be able to detect a change in status of a Resource shown in the COP and must provide notice to ERCOT operators of changes that a QSE makes to its COP.
(8)	A QSE representing a Resource that has an Energy Offer Curve valid for an hour of the COP may not designate a Resource Status of ONOS or ONDSR for that hour for that Resource.
[NPRR1000:  Replace paragraph (8) above with the following upon system implementation:]
(8)	A QSE representing a Resource that has an Energy Offer Curve valid for an hour of the COP may not designate a Resource Status of ONOS for that hour for that Resource.
3.10	Network Operations Modeling and Telemetry
(1)	ERCOT shall use the physical characteristics, ratings, and operational limits of all Transmission Elements of the ERCOT Transmission Grid and other information from the Transmission Service Providers (TSPs) and Resource Entities to specify limits within which the transmission network is defined in the network models made available to Market Participants as noted below and used to operate the ERCOT Transmission Grid as updated.  If a Private Use Network is not registered as a Resource Entity, then ERCOT shall use equivalent model data provided by TSPs, if available, that represents the Private Use Network in the TSPs' modeling systems for use in the Network Operations Model.
[NPRR857:  Replace paragraph (1) above with the following upon system implementation and satisfying the following conditions: (1) Southern Cross provides ERCOT with funds to cover the entire estimated cost of the project; and (2) Southern Cross has signed an interconnection agreement with a TSP and the TSP gives ERCOT written notice that Southern Cross has provided it with:  (a) Notice to proceed with the construction of the interconnection; and (b) The financial security required to fund the interconnection facilities:]
(1)	ERCOT shall use the physical characteristics, ratings, and operational limits of all Transmission Elements of the ERCOT Transmission Grid and other information from Transmission Service Providers (TSPs), Direct Current Tie Operators (DCTOs), and Resource Entities to specify limits within which the transmission network is defined in the network models made available to Market Participants as noted below and used to operate the ERCOT Transmission Grid as updated.  If a Private Use Network is not registered as a Resource Entity, then ERCOT shall use equivalent model data provided by TSPs, if available, that represents the Private Use Network in the TSPs' modeling systems for use in the Network Operations Model.
(2)	Because the ERCOT market requires accurate modeling of Transmission Elements in order to send accurate Base Points and pricing signals to Market Participants, ERCOT shall manage the Network Operations Model.  By providing Base Points and pricing signals by Electrical Bus to Market Participants, the Market Participants' responses result in power flows on all Transmission Elements that ERCOT must monitor and, if necessary for reliability reasons, manage within ratings provided by the TSP and Resource Entity and limits assigned by ERCOT including Generic Transmission Limits (GTLs) as may be defined in Section <IP_ADDRESS>, Use of Generic Transmission Constraints and Generic Transmission Limits.
[NPRR857:  Replace paragraph (2) above with the following upon system implementation and satisfying the following conditions: (1) Southern Cross provides ERCOT with funds to cover the entire estimated cost of the project; and (2) Southern Cross has signed an interconnection agreement with a TSP and the TSP gives ERCOT written notice that Southern Cross has provided it with:  (a) Notice to proceed with the construction of the interconnection; and (b) The financial security required to fund the interconnection facilities:]
(2)	Because the ERCOT market requires accurate modeling of Transmission Elements in order to send accurate Base Points and pricing signals to Market Participants, ERCOT shall manage the Network Operations Model.  By providing Base Points and pricing signals by Electrical Bus to Market Participants, the Market Participants' responses result in power flows on all Transmission Elements that ERCOT must monitor and, if necessary for reliability reasons, manage within ratings provided by each TSP, DCTO, and Resource Entity and limits assigned by ERCOT including Generic Transmission Limits (GTLs) as may be defined in Section <IP_ADDRESS>, Use of Generic Transmission Constraints and Generic Transmission Limits.
(3)	TSPs and Resource Entities shall provide ERCOT with equipment ratings and update the ratings as required by ERCOT.  ERCOT may request TSPs and Resource Entities to provide detailed information on the methodology, including data for determination of each requested rating.  ERCOT may review and comment on the methodology.  ERCOT shall post all methodologies on the Market Information System (MIS) Secure Area within seven days following a change in methodology.
[NPRR857:  Replace paragraph (3) above with the following upon system implementation and satisfying the following conditions: (1) Southern Cross provides ERCOT with funds to cover the entire estimated cost of the project; and (2) Southern Cross has signed an interconnection agreement with a TSP and the TSP gives ERCOT written notice that Southern Cross has provided it with:  (a) Notice to proceed with the construction of the interconnection; and (b) The financial security required to fund the interconnection facilities:]
(3)	Each TSP, DCTO, and Resource Entity shall provide ERCOT with equipment ratings and update the ratings as required by ERCOT.  ERCOT may request that a TSP, DCTO, or Resource Entity provide detailed information on the methodology, including data for determination of each requested rating.  ERCOT may review and comment on the methodology.  ERCOT shall post all methodologies on the Market Information System (MIS) Secure Area within seven days following a change in methodology.
(4)	ERCOT must use system ratings consistent with the ratings expected to be used during Real-Time for the system condition being modeled, including Dynamic Ratings using expected temperatures for those system conditions.  For each model, ERCOT shall post ratings and the ambient temperatures used to calculate the ratings on the MIS Secure Area when the model is published.
(5)	ERCOT shall use consistent information within and between the various models used by ERCOT in a manner that yields consistent results.  For operational and planning models that are intended to represent the same system state the results should be consistent and the naming should be identical.
(6)	ERCOT shall use a Network Operations Model Change Request (NOMCR) process to control all information entering the Network Operations Model.  In order to allow for construction schedules, each NOMCR must be packaged as a single package describing any incremental changes and referencing any prerequisite NOMCRs, using an industry standard data exchange format.  A package must contain a series of instructions that define the changes that need to be made to implement a network model change.  ERCOT shall verify each package for completeness and accuracy prior to the period it is to be implemented.
(7)	ERCOT shall use an automated process to manage the Common Information Model (CIM) compliant packages loaded into the Network Operations Model as each construction phase is completed.  ERCOT shall reject any NOMCRs that are not CIM compliant.  Each CIM compliant NOMCR must also be associated with commands to update the graphical displays associated with the network model modification.  During the testing phase, each NOMCR must be tested for proper sequencing and its effects on downstream applications.
(8)	ERCOT shall track each data submittal received from TSPs via the NOMCR process and from Resource Entities via the Resource Registration process.  Resource Registration data is converted by ERCOT to the appropriate NOMCR format through implementation and final testing of the change.  ERCOT shall notify each TSP and Resource Entity when the requested change is processed and implemented in accordance with Section 3.10.1, Time Line for Network Operations Model Changes.  ERCOT shall also provide the submitting TSP a link to a Network Operations Model containing the change for verifying the implementation of the NOMCR and associated one-line displays.  ERCOT shall post all NOMCRs on the MIS Certified Area for TSPs only within five Business Days following receipt of the NOMCR, consistent with the requirements regarding ERCOT Critical Energy Infrastructure Information (ECEII) set forth in Section 1.3, Confidentiality.  When posting a NOMCR, each change must be posted using the CIM data exchange format showing incremental changes to the last Network Operations Model for TSPs only, to facilitate TSPs in updating their internal network models to reflect changes made at ERCOT.  For each NOMCR, ERCOT shall post on the MIS Certified Area for TSPs only the current status on the in-service date for each NOMCR, including any prerequisite NOMCRs provided by the requestor.