presentation - fall 2014 release settlements training
TRANSCRIPT
Fall 2014 Release Settlements
Training
Cynthia Hinman
External Training
September 3, 2014
These fall 2014 release projects impact settlements
Project Name aka:
Contingency Reserve Cost Allocation FERC Order 789
Standard Capacity Product Availability Calculations Many-to-Many
Flexible Resource Adequacy and Must Offer Obligation FRAC MOO
Full Network Model Expansion FNM Expansion
Energy Imbalance Market EIM
Page 2
Contingency Reserve Cost Allocation
FERC Order 789
Page 3
What is it?
• Contingency reserve obligations specify the quantity and
types of spinning and non-spinning reserves required to
ensure reliability under normal and abnormal conditions.
– FERC Order 789 updates the current reserve
requirements
– Change will be effective October 1, 2014
• Due to changing requirements cost allocation will also
change.
Page 4
The minimum contingency reserve calculation is based
on the greater of:
The amount of Contingency Reserve equal to the loss of the most severe single contingency;
The amount of Contingency Reserve equal to the sum of three percent of hourly integrated Load plus three percent of hourly integrated generation.
Page 5
AS operating reserve obligation
Page 6
SPN / NSPN Obligation = 7% (ML + FE - FI) +
100% (NFI) +
0% (NFE) +
-2% (Hydro)
ML = Metered Load
FE = Firm Export
FI = Firm Import
NFI = Non-Firm Import
NFE= Non-Firm Export
(CC 6194 / 6294)
AS operating reserve obligation
Page 7
SPN / NSPN Obligation =
6% Load + 3% Exports – 3% Imports
( CC 6194 / 6294)
Impacted Charge Codes
Charge Code Title
Pre-calc Ancillary Service
6194 Spinning Reserve Obligation Settlement
6294 Non-Spinning Reserve Obligation Settlement
6090 Ancillary Service Upward Neutrality Allocation
Page 8
Example
Page 9
Notes
• Scheduling Coordinator’s hourly initial obligation can be
less than zero
• Dynamics are excluded if ISO is procuring AS for them
• Requires responsible entities to restore contingency
reserves within 60 minutes following a Disturbance
Recovery Period (as opposed to 90 minutes under the
NERC Reliability Standard)
Page 10
Page 11
Standard Capacity Product (SCP)
Availability Calculations Part of the Many-to-Many Substitution project
Page 12
Standard Capacity Product (SCP) Availability
Calculations
• With the introduction of the Outage Management System
(OMS), newly defined outage categories impact the
settlement of SCP
• Outage MWs associated with approved forced outages
that are not subject to SCP shall be exempted within the
SCP pre-calculation configuration
Page 13
New Fields in OMS
• Opportunity
– Off Peak Opportunity
– Short Notice Opportunity
• SCP Exempt Flag
– The exempt MW capacity is not part of the availability
assessment
– Automatically set in OMS based on business rules
• Nature of Work
Page 14
When is the “SCP exempt” flag set?
Outage Type Difference between
date of outage
submission and
planned start date/time
of outage *
SCP Exempt Flag is set
Forced 4-7 calendar days Yes
Forced 3 calendar days or less No
Planned N/A No
Page 15
(*excluding the date outage was submitted and planned start date of outage)
Example 1 – SCP Availability Calculation
• Assumptions
– A resource has a Pmax of 100 MW
– 1 assessment hour (60 min)
– Two forced outages
• Outage 1
• Outage 2
Page 16
Period Curtailed by
Minute 0 to 30 50 MW
Minute 31 to 60 0 MW (fully available)
Period Curtailed by
Minute 0 to 42 0 MW (fully available)
Minute 43 to 60 100 MW (fully curtailed)
Example 1 – SCP Availability Calculation (cont’d)
Page 17
100 MW Pmax
- 25 MW Outage 1
- 30 MW Outage 2
45 MW Resource availability
Example 2 – SCP Availability Calculation
• Assumptions
– A resource has a Pmax of 100 MW
– 1 assessment hour (60 min)
– Two forced outages
• Outage 1
• Outage 2 – Reported 5 days prior to outage
(SCP exempt forced outage)
Page 18
Period Curtailed by
Minute 0 to 60 40 MW
Period Curtailed by
Minute 0 to 60 50 MW
Example 2 – SCP Availability Calculation (cont’d)
Page 19
100 MW Pmax
- 40 MW Outage 1
60 MW Resource availability
BPM Configuration Guide: Standard Capacity Product
Pre-calculation (Updated Business Rules)
• SCP exempt capacity MWs shall not be subject to SCP
Non-Availability Charges and Availability Payments.
• A resource’s MW Capacity entered into a grandfathered
contract as specified in Tariff Section 40.9.2(2) & (3) shall
be treated as SCP exempt capacity.
• Outage MW Capacity associated with an RA
maintenance outage or short-notice opportunity outage
that is approved as a forced outage not subject to SCP
shall be treated as SCP exempt capacity.
Page 20
New Input Variable Name
• Represents the RA Capacity exempt from SCP due to:
– RA Maintenance outage
– Off-Peak Opportunity RA Maintenance Outage
– Short Notice Opportunity Outage
Page 21
BARAResourceOutageExemptQuantity BrtF’S’mdh
New Output Variable Name
Pre 10/1/14
• BAHourlyRAResourceSCPCapacityNotGrandfatheredQuantity BrtF’S’mdh
After 10/1/14
• BAHourlyRAResourceSCPCapacityNonExemptQuantity BrtF’S’mdh
Page 22
Page 23
Flexible Resource Adequacy Criteria
and Must Offer Obligation FRAC MOO
Page 24
Why do we need backstop capacity?
SC for LSE does not submit a plan that meets its flex RA requirement and does not cure the
deficiency
ISO’s monthly RA assessment
indicates that there is insufficient capacity
for a particular category
The ISO may exercise backstop
procurement to meet the operational flex
needs
Page 25
Key points - FRAC MOO Settlements
• Settlement starts January 1, 2015
• Two CPM types:
– CPM (for generic capacity)
– CPM Flexible Capacity
Page 26
Changes to the “Metered Demand Over TAC Area and
CPM Pre-Calculation”
• Purpose – Determines the metered demand allocation
by TAC Area(s) (minus qualified TORs), CPM payment
quantity, CPM allocation factors, and CPM availability
percentages for the settlement of CPM Capacity.
• Affects the following charge codes:
Page 27
Charge Code/ Pre-calc Name
CC 7872 – Monthly CPM Significant Event Settlement
CC 7873 – Monthly CPM Significant Event Allocation
CC 7874 – Monthly CPM Insufficient Local Capacity Area Resources Settlement
CC 7876 – Monthly CPM Collective Deficiency Settlement
CC 7877 – Monthly CPM Collective Deficiency Allocation
CC 7880 – Monthly CPM Exceptional Dispatch Settlement
CC 7882 – Monthly CPM Capacity at Risk of Retirement Settlement
CC 7883 – Monthly CPM Capacity at Risk of Retirement Allocation
CC 7884 – Monthly CPM Insufficient Resource Adequacy Resources Settlement
CC 7881 – Monthly CPM Exceptional Dispatch Allocation
Changes to the “Metered Demand Over TAC Area and
CPM Pre-Calculation” – Business Rules
• A resource with overlapping CPM and CPM Flex
Capacity shall be paid based on the highest MW amount
of either designation for the period when the
designations overlap (Rule 3.0)
Page 28
MW
CPM – Generic RA
CPM – Flex RA
Both of these are CPMs are for the same
period. The payment will be based on the
highest MW amount.
Changes to the “Metered Demand Over TAC Area and
CPM Pre-Calculation”- Business Rules (cont’d)
• For overlapping CPM capacity, the resource’s CPM
settlement shall be reflected in the Flexible CPM charge
code. (Rule 3.1)
– New charge codes
• CC 7886 – Monthly CPM Flexible Resource
Adequacy Resources Settlement
• CC 7887 – Monthly CPM Flexible Resource
Adequacy Resources Allocation
Page 29
Changes to the “Metered Demand Over TAC Area and
CPM Pre-Calculation”- Business Rules (cont’d)
• For a resource with more than two concurrent CPM
designations, where one of these designations is for
Flexible CPM, the overlapping capacity shall be
proportionate to the generic RA CPM designation. (Rule
3.2)
Page 30
CPM – Generic RA
CPM – Flex RA
60 MW
40 MW
Exceptional Dispatch
Monthly RA
The payment amount is based on the highest MW = 60 MW
Settlement Quantities =
20/60 X 20 = 6.6 MW ED CPM (Generic RA)
40/60 X 20 = 13.3 MW Monthly RA CPM (Generic RA)
40 MW Flex RA CPM
Legend
Changes to the “Metered Demand Over TAC Area and
CPM Pre-Calculation”- Business Rules (cont’d)
• For a resource with concurrent CPM designations, where
one of these designations is for Flexible CPM, the cost
allocation shall be proportionate to the deficiency MW
from both the generic and flexible resource adequacy
capacity. (Rule 4)
Page 31
CPM – Generic RA
CPM – Flex RA
2/3 Generic Capacity x CPM Payment = Generic Allocation
1/3 Flex Capacity x CPM payment = Flex Allocation
80 MW
40 MW
New charge code - Monthly CPM Flexible Resource
Adequacy Resources Settlement (CC 7886)
• Settlement of CPM capacity that the ISO procures in
response to all flex RA CPM designations
• Applies the CPM price
• Provides the total amount of SC payment for flex RA
CPM capacity procured during the trade month
• So this would also include overlapping generic CPM
capacity
Page 32
New charge code - Monthly CPM Flexible Resource
Adequacy Resources Allocation (CC 7887)
• Allocation of the cost of the CPM capacity procured in
the event that an SC fails to demonstrate an annual or
monthly RA plan procurement of sufficient flex RA
resources to comply with their LSE requirements
• Allocations will be prorated to each LSE based on the
proportion of its deficiency to the aggregate deficiency
• Monthly charge
Page 33
Example – Flex RA Allocation
Page 34
Changes to “RUC No Pay Quantity Pre-Calculation”
• Rescinds RUC capacity payment for resources when
one of the following occurs:
– RUC capacity is availability-limited
– Undispatchable due to an outage or rerate
– Is undelivered outside of a tolerance band
– Ineligible for a RUC award because it is RA capacity
(generic or flex)
• The calculation has been changed so that flex RA
capacity will be included
Page 35
Summary
• CPM designation – minimum commitment term of one month;
maximum 1 year.
• Same price for backstop procurement of flexible as the applicable
capacity procurement price mechanism.
• Cost for a CPM designation will be allocated to all deficient LSEs
within the deficient LRA (unless the LRA has established other
rules).
• Simultaneous or overlapping designations - the megawatt amount
of the capacity procurement mechanism capacity payments shall be
the highest megawatt amount of either designation.
Page 36
Page 37
Full Network Model Expansion
Transaction IDs and Registered Resources
Page 38
Phase 1 and
Phase 2 changes
39
October 1, 2014
Applications impacted by this change
Page 40
Application What is it? Change
Master File Holds resource-specific
information
Define external BAA scheduling points
SIBR Bid/Schedule/Forecast
submission
Transaction IDs will be created based on
SC submission
DAM/RTM Day-ahead and Real-time
market
Receive transaction IDs, perform
analysis which includes external BAA
constraints and outages
CMRI Market Reports Use transaction IDs (as applicable) in
reports
ADS Binding instructions Use transaction IDs (as applicable) in
ADS instructions
Settlements Market settlement
information
Use transaction IDs (as applicable) for
settlements
Use intertie/scheduling point combination
Intertie transaction inputs
Field Description
Scheduling Coordinator Scheduling Coordinator identifier (required)
Scheduling Point Intertie Scheduling Point identifier (required)
Primary Tie Primary Intertie identifier (required)
Direction Direction (required): I for import, E for export
Bid Type Bid Type (inserted): P for physical, V for Virtual
Alternate Tie Alternate Intertie identifier (optional)
Energy Type Energy Type (required for physical transactions):
F – Firm
N – Non-Firm
U – Unit Contingent
D – Dynamic Interchange
W – Wheeling
Purchase- Selling Entity
Identifier
A registered Purchase-Selling Entity identifier
(required for physical transactions); allow PSE,
PSE.1, PSE.2 …PSE.9
41
Intertie Transaction - fictitious examples
Non-resource specific Physical Import bid :
SC05-AMARGOSA_1_SN001-AMARGO-I-P-F-DECM01
SC05-AMARGOSA_1_SN001-AMARGO-I-P-F-DECM01.1
SC05-AMARGOSA_1_SN001-AMARGO-I-P-F-DECM01.2
…
SC05-AMARGOSA_1_SN001-AMARGO-I-P-F-DECM01.9
Non-resource specific Physical Export bid:
SC05-AMARGOSA_1_SN001-AMARGO-E-P-F-DECM01
SC05-AMARGOSA_1_SN001-AMARGO-E-P-F-DECM01.1
Non-resource specific Physical Wheeling Import bid:
SC05-AMARGOSA_1_SN001-AMARGO-I-P-W-DECM01
Non-resource specific Physical Wheeling Export bid:
SC05-BLYTHE_1_N101-BLYTHE-E-W-P-DECM01
Page 42
Scheduling
Coordinator
Intertie Scheduling
Point
Primary Intertie
Identifier
Direction
Bid Type
Energy Type
Purchase-Selling
Entity Identifier
Transaction ID
43
FMM Schedule – Effective Intertie
44
Transaction ID includes the
primary tie information
Effective Intertie – will show which tie
was used (primary or secondary, if
applicable)
Settlements
• Scheduling point and intertie will both be considered in
settlements
• This will be accounted for in the attributes of the
formulas.
• In Phase 1, there is a one-to-one correspondence
between scheduling point and the intertie, so this change
will have minimal system configuration impact
45
Old Attribute New Attributes
Financial Node APNode
APNode type
Intertie ID
Pricing Node
Example
Today After 10/1/14
HourlyDAFinancialNodeMCLPricej’mdh HourlyDAFinancialNodeMCLPriceAA’pmdh
Page 46
Attachments
Page 47
Energy Imbalance Market
EIM
Page 48
Real-time energy charge codes
CAISO Charge
Code
PACE Charge
Code
PACW Charge
Code
Instructed Imbalance
Energy (IIE)
6460 FMM
6470 RTD
64600 FMM
64700 RTD
64600 FMM
64700 RTD
Uninstructed Imbalance
Energy (UIE)
6475 64750 64750
Unaccounted for Energy
(UFE)
6474 64740 64740
Congestion Offset 6774 67740 67740
Marginal Losses Offset 6985 69850 69850
Imbalance Energy Offset
(RTIEO)
6477 64770 64770
Page 49
REAL-TIME CONGESTION
OFFSET
EIM settlement changes
Page 50
Real-time congestion offset
Step 1 - Real time dispatch is used to resolve load
imbalances
Page 51
PACW
PACE
1000 MW Demand
- 100 MW from ISO
= 900 MW from PACE or PACW
ISO
1000 MW Demand
+ 100 MW to PACE
= 1100 MW Dispatch
100 MW
Real-time congestion offset
Step 2 - Building buckets
Page 52
PACW PACE
900 MW X $40 = $36,000
ISO
1100 MW X $30 = $33,000
100 MW
Assume
- PACE LMP is $40
- ISO LMP is $30 Assume MCC =
$0 PACW
$2 PACE
$4 ISO
Real-time congestion offset
Step 3 - Congestion settlement (CC 6774, 67740)
Page 53
ISO
1,100 MW X $30 = $33,000
1,100 MW X $0 = $0 PACW
1,100 MW X $2 = $2,200 PACE
1,100 MW X $4 = $4,400 ISO
Total congestion = $6,600
Congestion cost due to ISO’s dispatch
Assume MCC =
$0 PACW
$2 PACE
$4 ISO
Allocation
• Allocated to ISO Measured Demand
Charge Code 6774
• Allocated to EIM Entity SC
Charge Code 67740
Page 54
Key concept – virtual bid adjustment
• “The CAISO Real-Time Congestion Charges less Virtual
Bid Adjustment shall be distributed back to non-ETC
Control Area metered Demand and exports in Real Time
Congestion Offset (CC 6774)”
• If virtual bid causes real time congestion in EIM BAA the
Virtual Bid adjustment will be charged to the virtual
bidders who caused the congestion
Page 55
REAL-TIME LOSS OFFSET
EIM settlement changes
Page 56
Key Concepts
• The Real Time Marginal Losses Offset for each BAA is
the sum for each BAA of the product of the contribution
of that Balancing Authority Area’s Transmission
Constraints to the marginal loss component of the LMP
at each resource location in the EIM Area and the
imbalance energy, at that resource
• If energy is all flowing into ISO then all the losses will be
part of ISO allocation.
Page 57
Allocation
• Allocated to ISO Measured Demand
Charge Code 6985
• Allocated to EIM Entity SC
Charge Code 69850
Page 58
REAL-TIME IMBALANCE
ENERGY OFFSET
EIM settlement changes
Page 59
Real-time Imbalance Energy Offset
• Total Energy Imbalance Offset
= (IIE + UIE + UFE) – Congestion – Losses
= ((6460 +6470) + 6475) – 6774 – 6474)
or
= ((64600 +64700) + 64750) – 67740 – 64740)
Page 60
Real-time Imbalance Energy Offset
• Total Energy Imbalance Offset
– EIM Transfer falls into this bucket
– Allocated to other BAAs
– Could be a payment or a charge
Page 61
Real-time imbalance energy offset
Step 1 - Real time dispatch is used to resolve load
imbalances
Page 62
PACW
PACE
1000 MW Demand
- 100 MW from ISO
= 900 MW from PACE or PACW
ISO
1000 MW Demand
+ 100 MW to PACE
= 1100 MW Dispatch
100 MW
Real-time imbalance energy offset
Step 2 – Building buckets
Page 63
PACW
PACE
900 MW X $40 = $36,000
+ 100 MW X $30 = $ 3,000
$39,000
ISO
1100 MW X $24 = $26,400
- 100 MW X $30 = $ 3,000
$ 23,400
100 MW
Assume
- PACE LMP is $40
- ISO LMP is $30
The price for the BA transfer quantity (100 MW) based on the transfer
scheduling point ($30)
Determine the total “transfer from” amount
• The total “transfer from” = sum of the absolute value of
UIE, UFE and the EIM transfer quantity
• Transfer Out % x BAA RTIEO = Transfer from amount
5% x $23,400 = $1,170
Page 64
Determine total “transfer to” amount
• The transfer to amount = Sum of transfer from $ *
transfer to %
$1,170 x 20% = $234.00
Page 65
Page 66
FLEXIBLE RAMPING
CONSTRAINT
EIM settlement changes
Page 67
Tariff section 11.25 Flexible Ramping Constraint
subsections
• Determination of shadow price 11.25.1
• Compensation of resources (payment) 11.25.2
• Rescission of payment for non-performance (no pay) 11.25.3
• Apportionment of costs 11.25.4
• Allocation of costs 11.25.5
Page 68
Charge code 7050 – Flexible Ramp Up Capacity
Payment
• Applied to resources with awarded flex ramping capacity
which resolve the flexible ramping constraint(s) in the
EIM area in which they participate in the FMM.
Page 69
Payment per resource = capacity award X derived price
Flexible ramping constraint derived price
• Equal to the lesser of:
– $800/MWh or
– Greater of
• Zero or
• Real-time spinning reserve ancillary service marginal price or
• Flexible ramping constraint shadow price minus 75% of the
maximum of
– Zero or
– The simple average real-time SMEC for each of 3 five
minute intervals in the applicable FMM interval
Page 70
=min($800,max(0, AS Spin, (FRC -.75 x max (0, RT SMEC))))
Example 1 – Determining the derived price
• Assumptions
– Flexible ramp constraint award 10 MW
– Flexible ramp constraint price $250
– AS Spin price $3
– RT SMEC (simple average) $200
Page 71
=min($800, max(0, $3, ($250 - .75 X max (0, $200))))
=min($800, max(0, $3, ($250 - .75 x 200)))
=min($800, max(0, $3, ($250- $150)))
=min($800, max(0, $3, $100))
=min($800, $100)
=$100 (the derived price)
Page 72
=min($800,max(0, AS Spin, (FRC -.75 x max (0, RT SMEC))))
Example 1 – Determining the derived price
Example 2a – Determining the derived price
• Assumptions
– Flexible ramp constraint award 10 MW
– Flexible ramp constraint price $100
– AS Spin price $3
– RT SMEC (simple average) $200
Page 73
=min($800, max(0, $3, ($100 - .75 X max (0, $200))))
=min($800, max(0, $3, ($100- .75 x 200)))
=min($800, max(0, $3, ($100- $150)))
=min($800, max(0, $3, -$50))
=min($800, $3)
=$3 (the derived price)
Page 74
=min($800,max(0, AS Spin, (FRC -.75 x max (0, RT SMEC))))
Example 2a – Determining the derived price
Example 2b – Determining the derived price
• Assumptions
– Flexible ramp constraint award 10 MW
– Flexible ramp constraint price $100
– AS Spin price $0 (EIM Entity)
– RT SMEC (simple average) $200
Page 75
=min($800, max(0, $0, ($100 - .75 X max (0, $200))))
=min($800, max(0, $0, ($100 - .75 x 200)))
=min($800, max(0, $0, ($100 - $150)))
=min($800, max(0, $0, -$50))
=min($800, $0)
=$0 (the derived price)
Page 76
=min($800,max(0, AS Spin, (FRC -.75 x max (0, RT SMEC))))
Example 2b – Determining the derived price
Examples - settlements
Page 77
Example Capacity
Award
Derived
Price
Payment in
CC 7050
1 10 MW $100 $1,000
2a 10 MW $ 3 $ 30
2b 10 MW $ 0 $ 0
Other charge codes related to the flexible ramping
constraint
• The allocation of the total flexible ramping constraint
costs for each EIM Entity Balancing Authority Area will
be allocated to the applicable EIM Entity SC in charge
code 7056.
• If resource that was awarded flexible capacity, fails to
deliver, they will be subject to “Flexible Ramp Up
Capacity No Pay Charge” in charge code 7024.
Page 78
Example – Resource Flexible Ramping Allocation
• Assumptions
200 MW Awarded
10 MW No Pay
190 MW Delivered
• Resource Specific Flexible Ramping Marginal Price =
$16.28
– Based on the resource’s total FRC cost in all BAAs
• Flexible Ramping Constraint Price = $10.00
Page 79
Charge code 7056 – Flexible Ramp Cost Allocation
Page 80
MW Delivered x FRC Price
Apportionment x Flexible Ramping Marginal Price
Total Cost x % allocation
ISO BAA allocates to measured
demand and gross negative supply
deviation
Page 81
BID COST RECOVERY
NETTING CHANGE
EIM settlement changes
Page 82
EIM BCR sequential netting
Each interval the ISO will:
1. Determine if there is a shortfall
2. Calculate the 5-minute BCR pre-transfer amount
3. Calculate to the amount attributed to transfer out
4. Calculate the % of transfer allocated to transfer in and
transfer out
5. Calculate the amount of transfer in or transfer out $
6. Calculate the 5-minute BCR total
Page 83
Example BCR netting – Step 1
• Compare costs and revenues for each generator in BAA
and determine if there is a shortfall
Page 84
Example BCR netting – Step 2
• Determine the 5-minute BCR pre-transfer amount for
each BAA
Page 85
5-Minute BCR Pre-Transfer = Daily BCR/24/12
Example BCR netting – Step 3
• Determine the total transfer out which is the sum of the
absolute value of UIE, UFE and the EIM transfer quantity
Page 86
• Determine the BCR % transfer out by dividing the EIM
transfer quantity by the transfer out amount
• Determine the BCR % transfer in by adding EIM transfer
quantity for each BAA and dividing by the sum of the
total positive EIM transfer quantity
Example BCR netting – Step 4
Page 87
Example BCR netting – Step 5
• Apply the BCR % transfer in or out to the 5-minute BCR
pre-transfer amount to determine the credit or debit
amount
Page 88
Example BCR netting – Step 6
• Sum the 5-minute BCR pre-transfer amount and the
transfer in or transfer out $ to determine the 5-minute
BCR total
Page 89
Page 90
OVER AND UNDER
SCHEDULING CHARGES
EIM settlement changes
Page 91
Key concepts
• Unique to participation in EIM
– Impacts all BAAs
• Purpose – To ensure that EIM Entity BAAs are not
leaning on the system to meet its load forecasts
• Charge codes
– 6045 – Over and Under Scheduling EIM Settlement
– 6046 – Over and Under Scheduling EIM Allocation
Page 92
Over scheduling charge
• Using EIM Entity forecast
– If EIM Entity demand is less than the base schedule
of supply by
• More than 5% but less than 10% and by at least 2
MW, the UIE for that LAP will be paid at 75% of the
hourly price
• More than 10% and by at least 2 MW the UIE for
that LAP will be paid at 50% of the hourly price
• Using Market Operator forecast
– If forecast is < EIM Entity base schedule supply by >
1% then deemed to be using their own forecast and
subject to penalties above
Page 93
Under scheduling charge
• Using EIM Entity forecast
– If EIM Entity demand exceeds the base schedule of
supply by
• More than 5% but less than 10% and by at least 2
MW, the UIE for that LAP will be paid at 125% of
the hourly price
• More than 10% and by at least 2 MW the UIE for
that LAP will be paid at 200% of the hourly price
• Using Market Operator forecast
– If forecast is < EIM Entity base schedule supply by >
1% then deemed to be using their own forecast and
subject to penalties above Page 94
Page 95
GRID MANAGEMENT
CHARGES
EIM settlement changes
Page 96
Charge Code 4564 – GMC EIM Transaction Charge
• Unique to participation in EIM
– Participating generator
– Non-Participating generator
– Intertie Resources
– Load
• Covers staff and portions of the ISO systems used to
support EIM functionality.
* Total gross absolute value
Page 97
Charge Code 4564 – GMC EIM Transaction Charge
• EIM Administrative Charge = $.19
• Base charge = 5% of supply + 5% of demand
• Charge for each EIM Participating and Non-participating
resource
– If this amount exceeds the base charge no additional
charges go to the EIM Entity SC
– If this amount does not exceed the base charge the
difference is charged to the EIM Entity SC
* Total gross absolute value
= EIM Administrative Charge X (FMM IIE*, RTD IIE*, UIE* of EIM
supply + UIE* of EIM demand)
Page 98
Page 99
GREENHOUSE GAS EMISSION
COST REVENUE
EIM settlement changes
Page 100
Charge code 491 – Greenhouse Gas Emission Cost
Revenue
• Unique to participation in EIM
• EIM will incorporate the cost of the greenhouse gas
compliance obligation within an EIM Entity to serve ISO
load, but will not consider this cost when it dispatches
this generation to serve load outside of the ISO.
• Obligation quantity = Net export to the ISO BAA for each
EIM resource GHG payment
• GHG marginal price - based on MW that were
dispatched and determined to be awarded the GHG
obligation
GHG payment = GHG obligation quantity X EIM GHG marginal
price
Page 101
NEW ATTRIBUTES
EIM settlement changes
Page 102
New attributes, no change in calculation
Charge Code Name
4515 GMC Bid Transaction Fee
4560 GMC Market Services Charge (note – this will not apply
to resources in EIM BAA)
4561 GMC System Operations Charge (note – this will not
apply to resources in EIM BAA)
Page 103
Page 104