Market Settlements
Physical Bilateral Schedules
May 9th, 2011
Henry Chu
Kevin Krasavage
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• Kevin Krasavage
• Email: [email protected]
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2
Market Settlement Training Series
Market Settlements Training Modules:
–
–
–
–
–
–
–
–
Overview O101
ARR/FTR AF201
Virtual and Financial Schedules VF201
Physical Schedules PS201
Load L201
Generation G201
Generation Wind Farm GWF202
Overview O101
(Feb. 2011)
(Mar. 2011)
(Apr. 2011)
(May 2011)
(Jul. 2011)
(Aug. 2011)
(Sep. 2011)
(Oct. 2011)
3
MISO Disclaimer
The following training materials are intended for
use as training materials only and are not intended
to convey, support, prescribe or limit any market
participant activities. These materials do not act as
a governing document over any market rules or
business practices manual. The data used in the
examples is test data and should not be used to
support market analyses.
4
Key Assumptions
• This material will discuss Settlements concepts
centered on the Energy and Operating Reserves
Markets
• This is not a stakeholder meeting. The purpose of this
training is NOT to make or to debate market design
decisions, policies, or rules
• Participants will actively participate in the training by
asking constructive questions in an effort to improve the
overall learning experience
5
Course Objective
• Provide an overview of Physical Bilateral
Transactions and their role in the MISO.
• Review Physical Bilateral Transaction
Settlement charges in the Day-Ahead and RealTime Market.
6
Agenda
TOPICS
Physical Bilateral Transaction Overview
Physical Bilateral Transaction Market Concept and
Timeline
Physical Bilateral Transactions Systems
Interface Pricing and Asset Owner Determination
Physical Bilateral Settlement
Break
Physical Bilateral Transactions Common Disputes
Physical Schedule Settlement Example
Break
RSG_DIST1 Redesign Impact on Physical
Schedules.
Physical Bilateral Transactions Summary
SCHEDULE
12:30 to 12:45
12:45 to 13:00
13:00 to 13:20
13:20 to 13:45
13:45 to 14:00
14:00 to 14:15
14:15 to 14:30
14:30 to 15:15
15:15 to 15:30
15:30 to 16:00
16:00 to 16:15
7
Commonly Used Acronyms
CPN
Commercial Pricing Node
DA
Day-Ahead
DART
Day-Ahead/Real-Time
FBT
Financial Bilateral Transaction
GFA
Grandfathered Agreement
IDC
Interchange Distribution Calculator
LMP
Locational Marginal Price
MP
Market Participant
OASIS
Open Access Same Time Information System
OATI
Open Access Technology
OD
Operating Day
PBT
Physical Bilateral Transaction
PSE
Purchase Selling Entity
PSS
Physical Scheduling System
RT
Real-Time
TSR
Transmission Service Request
8
Introduction
Introduction
MISO Neighbors
10
Introduction
• What
is a Physical Bilateral Transaction?
- Represents an agreement between two parties
to import, export or move energy through
the MISO footprint.
11
Introduction
• Day Ahead Physical Schedules 2010 -2011
Number of Day Ahead Physical
Schedules
Day Ahead Physical Schedule
Volume
Fixed
GFACO
Fixed
GFACO
UP_TO_TUC
DISPATCH
UP_TO_TUC
DISPATCH
22%
0%
18%
40%
4%
46%
38%
32%
Approx. 110,000 schedules
Approx. 91 M MW
12
Introduction
• Real Time Physical Schedules 2010 -2011
Number of Real Time Schedules
Real Time Schedule Volume
Fixed
GFACO
Fixed
GFACO
UP_TO_TUC
DISPATCH
UP_TO_TUC
DISPATCH
0%
24%
2%
0%
0%
30%
76%
Approx. 182,000 schedules
68%
Approx. 102 M MW
13
Introduction
Functions of a Physical Bilateral
Transaction
• Physical Bilateral Transactions cause MISO energy prices to
be comparable with an external BA, contributing to
increased efficiency of the Energy Market.
• It provides an additional hedging mechanism for Market
Participants with physical load and generation.
• Opens the wholesale electric market to more participants,
ideally increasing market stabilization and liquidity.
14
Introduction
Physical Bilateral Transaction
MISO Market
PJM Market
$40
MISO LMP
Import
$ 55
PJM LMP
Buy 1 MW
Sell 1 MW
$15 profit
Sell 1 MW
Buy 1 MW
$15 loss
Export
$15 profit/loss assuming no transaction costs
15
Introduction
• Physical Bilateral Transactions Costs
Physical Bilateral
Transaction Costs
Energy Market
Transmission
Costs
Costs
Energy Market
Transmission
Settlements
Settlements
16
Physical Bilateral Transactions
Overview
Physical Bilateral Transactions
• Physical Schedule Definition
• Physical Bilateral Interchange Schedules
• Physical Bilateral Energy and
Transaction Types
18
Physical Bilateral Transactions
• Physical Schedules
– Are schedules used to capture Physical Bilateral Transaction
information for the transfer of physical energy In, Out, and
Through the Market Footprint from in the MISO Day-Ahead and
Real-Time markets.
19
Interchange Schedules
• Interchange Schedules that either enter, exit or
cross the boundary of the Market Footprint are
classified as follows:
– Import Schedule
– Export Schedule
– Through Schedule
20
Internal Schedules
• Internal Physical Schedules that are within the
Market Footprint are classified as follows:
– GFA Carve Out Schedules
– GFA Carve Out Schedules are discussed in the
Financial Bilateral Transaction Training.
21
Import Schedule
MISO Market
Sink
Source
• If the Source Point is external to the MISO Market
footprint and the Sink Point is internal, the
Interchange Schedule is an Import Schedule.
22
Export Schedule
MISO Market
Source
Sink
• If the Sink Point is external to the MISO Market
footprint and the Source Point is internal, the
Interchange Schedule is an Export Schedule.
23
Through Schedule
MISO Market
Source
Sink
• If the Source Point and Sink Point are external to the
MISO Market footprint, the Interchange Schedule is a
Through Schedule.
24
Grandfathered Carve Out Schedule
MISO Market
Source
Sink
• If the Source Point and Sink Point are internal to the MISO
Market Footprint, the Interchange Schedule is a Grandfathered
Carve Out Schedule.
• Grandfathered Carve Out Schedules will be discussed in the
Financial Bilateral Transaction training.
25
Physical Bilateral Transactions
Market Concepts
Interchange Schedule Energy and
Transaction Types
Energy Types
Transaction
Types
Interchange
Schedules
Normal
Up To TUC
Dispatchable
Dynamic
Fixed
GFA Carve
Out
Fixed
GFA Carve
Out
27
Energy Types
• Normal
– This is the standard energy type. The hourly MW
amount is static and does not change after the fact.
– Scheduled in the Day-Ahead and Real-Time
Markets.
• Dynamic
– This energy type is agreed to by both parties and
requires metering. The original value on the tag is an
estimate. The estimated value is updated after the
fact by one of the parties to the schedule.
– Scheduled in the Real-Time market only.
28
Transaction Types
• Fixed
– Price Takers at External Interface LMP
– Day-Ahead/Real-Time Schedule option must be
selected and implemented before 11:00 AM on the
day prior
– Real-Time Schedule is used in Real-Time Market
– Schedule is limited to Transmission Reservation and
Ramp availability
– Wheel-In, Wheel-Out or Wheel-Through schedule
29
Transaction Types
• Dispatchable
- Created in the Day-Ahead Market
– Day-Ahead/Real-Time Schedule option must be
selected and implemented before 11:00 am on the
day prior
– E-Tag that specify a Bid or Offer ($/MWh)
– Day-Ahead Market determines the cleared volume
– Wheel-In or Wheel-Out
30
Transaction Types
• DISPATCH
31
Transaction Types
• UP_TO_TUC
– Created in the Day-Ahead Market
– Day-Ahead/Real-Time Schedule option must be
selected and implemented before 11:00 AM on the
day prior
– MPs can specify any amount of the Transmission
Usage Charge (TUC) they are willing to pay “up to”
example $1.00/MWh.
– Day-Ahead Market determines the cleared volume
– Wheel-In, Wheel-Out or Wheel-Through schedule
32
Transaction Types
• UP_TO_TUC
33
Transaction Types
• GFA Carve-Out
– Carve Out’s are entitled to a rebate for congestion
and loss.
– GFA Carve Out is discussed in the Financial Bilateral
Transaction training.
– Energy is settled outside of the MISO Market
– Day-Ahead/Real-Time or Real-Time only Schedule
– OATI under Fixed, Sub Type in PSS , Type in
Settlement
– Internal or External
34
Summary
• Physical Bilateral Transactions are agreements between
two parties to import, export or move energy through the
MISO footprint in the Day-Ahead/Real-Time markets
which is included in the Physical Schedule.
• Physical Schedules include the Interchange Schedule
Classification, Energy Type and Transaction Type.
• There are two energy types: Normal and Dynamics
• There are four main Transaction Types: Fixed, Up-to-TUC,
Dispatch and GFACO
35
Questions?
36
Physical Bilateral Transactions
Time Lines
Market Timelines
•
•
•
•
•
•
Day-Ahead Timeline
Day-Ahead Adjustment
Day-Ahead Market Adjustment
Real-Time Timeline
Real-Time Adjustment
Real-Time Curtailment
38
Day-Ahead Market Timeline
39
Day-Ahead Timeline
09:00
Approval
Time
11:00
• E-Tag should be submitted before HE9 in order to be
implemented by HE11 (OD-1).
• This allows each entity the 2 hour NERC approval time
limit for next day transactions.
• The PSS sends only the Interchange Schedules that
have reached their final status of “implemented” to
DART by HE11(OD-1).
40
Day-Ahead Market Adjustment
• What is a Day-Ahead Market Adjustment?
– After the close of the Day-Ahead Market, DayAhead/Real-Time schedules are evaluated by the
MISO and are adjusted accordingly depending on
their bids and offers. These schedules may fully or
partially clear depending on the LMP.
41
Day-Ahead Market Adjustment
8:00
• Market Participant submits a Dispatchable Day-Ahead/Real-Time
schedule HE1-HE10 50MW with a bid of $25 per MW on 1/30/2011
for Operating Day 1/31/2011.
9:00
• All parties approve the schedule on 1/30/2011.
• The schedule is now implemented.
• Market Cleared and the DA LMP was $26 per MW.
15:00
• Since the DA LMP $26 per MW was greater than the bid of $25
per MW the schedule will be adjusted to 0MW for HE1-HE10.
42
Real-Time Timeline
• All Interchange Schedules must begin and end on
the top, quarter past, half, or quarter till the hour.
• Interchange Schedules for the Real-Time Energy and
Operating Reserve Market must be submitted via
NERC E-Tag, no later than 30 minutes prior to the
start of the schedule; however, Interchange
Schedules may not be submitted or modified during
the operating hour, except for reliability purposes as
determined by the Transmission Provider.
43
Real-Time Timeline
44
Real-Time Adjustment
• What is a Real-Time Adjustment?
– A Real-Time Adjustment is when the Market
Participant submits an adjustment to a Real-Time
Schedule during the Operating Day.
45
Real-Time Adjustment
7:00
• Market Participant submits a Real-Time Schedule HE11-HE15 45MW for
Operating Day 2/1/2011.
9:00
• All parties approve the Real-Time Schedule.
• The Real-Time Schedule is now implemented.
9:30
• Market Participant adjusts HE11 to 50MW.
• All Parties approve the adjustment and the adjustment becomes
implemented.
• The Real-Time Schedule would be HE11 50MW and HE12-H15
45MW.
46
Real-Time Curtailment
• What is a Real-Time Curtailment?
– A curtailment is issued by a Reliability Coordinator
due to a reliability issue with a transmission line.
– The Reliability Coordinator sends the curtailment
requirement to the Interchange Distribution Calculator
(IDC) which calculates the reduction in MW/h and
spreads the reduction across schedules utilizing the
transmission line.
47
Real-Time Curtailment
7:30
• Market Participant submits a Real-Time Schedule HE20-HE24
45MW for Operating Day 2/1/2011.
8:00
• All parties approve the Real-Time Schedule.
• The Real-Time Schedule is now implemented.
• Due to a reliability issue HE20-HE22 is reduced to 40MW.
18:00
• Market Participant would then be responsible for HE20-HE22
40MW and HE23-HE24 45MW.
48
Summary
• Day-Ahead/Real-Time schedules are created the day
before the operating day and should be submitted before
9:00 EST to be implemented by 11:00 EST.
• An Adjustment made to a Day-Ahead/Real-Time
schedule before 11:00 EST is a Day-Ahead Adjustment
and an Adjustment made to a Day-Ahead/Real-Time
schedule made after the close of the market is a DayAhead Market Adjustment.
49
Summary
• Real-Time Schedules are created during the operating
day, submitted no later than 30 minutes prior to schedule
start, begin and end at the top, quarter past, half past or
quarter till the hour and cannot be submitted or modified
during the operating hour.
• Real-Time adjustments are submitted during the
operating day.
• Curtailments are issued by the Reliability Coordinator
due to a transmission line reliability issue.
50
Questions?
51
Interface Pricing and
AO Determination
Interface Pricing Determination
•
•
•
•
Interface Pricing Definition
Interface Pricing Import Schedule
Interface Pricing Export Schedule
Interface Pricing Through Schedule
53
Interface Pricing Determination
• An external Commercial Pricing Node is where an
LMP will be calculated to settle Market Activities
associated with Import Schedules, Export Schedules
and Through Schedules.
• The LMP of the Internal Sink or Source of the tag is
not used.
54
Interface Pricing Determination
• MISO’s 80 External Interface CPNodes
AEC
CSWS
ERCO
ISNE
MHEB
ONT
RC
SPC
AECI
DEWO
FMPP
JEA
MIDW
ONT_W
SC
SPS
AEP
DLCO
FPC
KACY
MOWR
OPPD
SCEG
TAL
AP
DPL
FPL
KCPL
MPS
OVEC
SEC
TEC
BBA
DUK
GRDA
LAFA
NLR
PECO
SECI
TVA
CE
EDDY
GVL
LAGN
NPPD
PJMC
SEHA
VAP
CISO
EDE
HQT
LEPA
NSB
PLUM
SERU
WAUE
CLEC
EEI
HST
LES
NYISO
PNM
SME
WFEC
CPLE
EES
INDN
LGEE
OKGE
PSCO
SOCO
WR
CPLW
EKPC
IPRV
LWU
OMPA
PSEG
SPA
YAD
55
Interface Pricing Import Schedule
MISO Market
Sink
Source
Interface
CPNode
• The LMP for Import Schedules is determined at the
external interface commercial pricing node of the
Source where energy is being imported into MISO
Market.
56
Interface Pricing Import Schedule
MISO Market
CPNode
Interface 1
Source
Sink
CPNode
Interface2
• If external interface CPNode of the Source is not in
MISO model; then the CPNode where energy enters
into the MISO Market is used.
57
Interface Pricing Import Schedule
2
1
3
Interface Determination
1) Source
2) GCA
3) POR
58
Interface Pricing Export Schedule
MISO Market
Source
Sink
Interface
CPNode
• The LMP for Export Schedules is determined at the
external interface commercial pricing node of the Sink
if available.
59
Interface Pricing Export Schedule
MISO Market
Sink
Interface
Source
• The LMP for Export Schedules is determined at the
external interface commercial pricing node of the Sink
if available or the PODR at MISOTP.
60
Interface Pricing Export Schedule
3
2
1
Interface Determination
1) Sink
2) LCA
3) PODR on MISO TP line
61
Interface Pricing Through Schedule
MISO Market
Source
CPN
CPN
Sink
• The LMP for Through Schedules is determined at the
external interface commercial pricing nodes where
energy is being imported and exported from the MISO
Market and is the difference between the two LMP’s.
62
Interface Pricing Through Schedule
MISO Market
Source
$30
$25
Sink
• Interface Pricing Through Schedule: Example 1
– If the LMP at the Source CPN is $30 and the LMP at the sink
CPN is $25 the Market Participant would be getting paid $5 per
MW.
63
Interface Pricing Through Schedule
MISO Market
Source
$25
$30
Sink
• Through Schedule: Example 2
– If the LMP at the Source CPN is $25 and the LMP at the
sink CPN is $30 the Market Participant would be paying $5
per MW.
64
Asset Owner Determination
• Who is the Financial Responsible Entity for the
Physical Schedules?
–
–
–
–
–
Scheduling Agent?
Source AO?
Sink AO?
Seller/Buyer of the Energy(PSE)?
Owner of the Import/Export MISO Transmission?
65
OATI – for tags
MISO uses the 1st
TSR listed on the tag to determine AO
(MISO transmission).
OASIS – Where to
access TSR info.
Type in TSR number
in “Assignment” field.
TSR number is obtained
from tag.
TSR entered. Hit
“Submit” button.
This is where the
Asset owner is listed.
Asset Owner Determination
Summary
• Who is the Financial Responsible Entity for the
Physical Schedules?
– Asset Owner of the Import/Export MISO
Transmission.
71
Questions?
72
Review
Question 1
• What represents an agreement between two parties
to import, export or move energy through the MISO
footprint?
A.
B.
C.
D.
Financial Bilateral Transaction
Transmission Service Request
Physical Bilateral Transaction
Normal Energy Type
74
Question 2
• Which of the following is a reservation for the use of
the transmission system that moves energy into, out
of and through the MISO footprint?
A.
B.
C.
D.
Normal Energy Type
Physical Bilateral Transaction
Financial Bilateral Transaction
Transmission Service Request
75
Question 3
• Who is the Financial responsible entity on
the Tag is ?
A.
B.
C.
D.
Purchasing/Selling Entity
Source/Sink Asset Owner
Scheduling Entity
Asset Owner of the Import/Export MISO
Transmission
76
Question 4
• This Energy Type is agreed to by both
parties and requires metering by both
parties. The estimated value is updated after
the fact?
A.
B.
C.
D.
Dynamic
Fixed
Dispatchable
Normal
77
Question 5
• Which Day-Ahead Physical Transactions
submitted via NERC E-Tag that specify a Bid
or Offer?
A.
B.
C.
D.
Dynamic
Fixed
Dispatchable
Normal
78
Question 6
• A Day-Ahead schedule should be submitted
before ___ hours EST (OD-1) to be
implemented by HE 11(OD-1)?
A.
B.
C.
D.
10:00
10:30
9:00
9:30
79
Question 7
• Where would I confirm the Financial
Responsible Entity information for the
Physical Schedules?
A.
B.
C.
D.
PSS
OASIS
OATI
PSE
80
Physical Bilateral Transactions
Systems
Physical Bilateral Transactions
Systems
Three systems are used by MISO to approve, track and
record Physical Bilateral Transactions:
 OASIS – Open Access Same-Time Information System
 OATI – Open Access Technology, Inc
 PSS – Physical Scheduling System
82
Principle and Concept of Tagging
• Schedules are created in the Day-Ahead and Real-Time Energy
Markets and define the physical path of energy from Source
point to the Sink point.
• Each Schedule has a unique electronic identification number
which is know as the E-Tag and is used by the Market
Participants to identify the schedule.
• Unique Tag IDs
• Each E-tag on which the MISO is included shall have a
unique tag ID. Each Tag ID will follow the same format:
(GCA)_(PSECODE)(Tag Code)_(LCA)
Example: LLC_JOHNC01RT08681_MISO
83
Open Access Same-Time
Information System (OASIS)
• Market Participants need transmission reservations to
ensure the flow of the energy for Physical Bilateral
Transaction request.
• Market Participants submit their transmission
reservation request through the MISO OASIS site.
• OASIS is the primary Internet-based transmission
reservation system used North America.
• The Transmission Reservation number is needed for
the E-tag.
84
Open Access Same-Time
Information System (OASIS)
MISO OASIS Overview
shows how to use the MISO
OASIS Site
85
Open Access Technology Inc.
(OATI)
• Market Participants use the OATI webTrans interface
Application to create the E-Tag with the appropriate
Transmission reservation information.
• Balancing Authorities use OATI to approve the E-Tag
after ensuring there is sufficient transmission reserved to
move the requested energy through their control area.
• MISO uses OATI as the interface between the MISO
internal Physical Scheduling System and the Market
Participants’.
www.oati.com/transmission.aspx
86
Open Access Technology Inc. (OATI)
www.oati.com/transmission.aspx
87
Physical Scheduling System
(PSS)
• The MISO internal system is the Physical Scheduling
System which processes and tracks the Interchange
Schedules that enter, exit or pass through the MISO’s
Market footprint.
• Market Participants can use PSS to see a cleared
schedule’s volume in MISO system.
• The PSS is the MISO system of record of for all
physical bilateral transactions and is the source for
MISO Settlements Systems.
88
Physical Scheduling System
(PSS)
89
Market Settlements Flow Diagram
Market
Participant
OASIS
OATI
PSS
DART
Market
Settlements
90
Market Settlements Flow Diagram
Market
Participant
OASIS
• A reservation is created in OASIS by completing a
Transmission Service Request which defines the
Physical Path of Energy and the Asset Owner.
91
Market Settlements Flow Diagram
Market
Participant
OATI
• Approved Transmission Service Requests are
transferred to OATI.
• Day-Ahead/Real-Time Schedules are created in OATI
and define the Operating Day, Scheduled MW per
hour, Asset Owner, Energy Type and Transaction
Type.
92
Market Settlements Flow Diagram
OATI
PSS
• Day-Ahead/Real-Time schedules that are approved
and implemented are transferred to PSS.
93
Market Settlements Flow Diagram
PSS
DART
• PSS transfers Day-Ahead/Real-Time schedules to
DART.
94
Market Settlements Flow Diagram
OATI
PSS
DART
• DART transfers Day-Ahead clearings to PSS.
• PSS transfers Day-Ahead clearings to OATI.
95
Market Settlements Flow Diagram
PSS
Market
Settlements
• Market Settlements receives Day-Ahead/Real-Time
schedule data from PSS.
96
Summary
• Tagging is the process of creating schedules in the DayAhead/Real-Time Markets and defining the path of energy from
Source to Sink.
• OASIS is the system in which Transmission Service Requests are
submitted.
• OATI is the system for creating E-tags and managing scheduling
activities.
• PSS is the MISO system of record which tracks interchange
schedules that enter, exit or pass through the MISO footprint.
97
Questions?
98
Review
Question 8
• This type of adjustment is issued by a
Reliability Coordinator due to a reliability
issue with a transmission line?
A.
B.
C.
D.
Day-Ahead Adjustment
Real-Time Adjustment
Day-Ahead Market Adjustment
Real-Time Curtailment
100
Question 9
• The ____ process and tracks Interchange
Schedules that enter, exit or pass through
the MISO footprint?
A. Open Access Technology Inc (OATI)
B. Open Access Same-Time Information System
(OASIS)
C. Physical Scheduling System (PSS)
D. DART
101
Question 10
• ____ is an internet based high-voltage
transmission reservation system for
obtaining services related to electric power
in North America?
A.
B.
C.
D.
DART
Physical Scheduling System (PSS)
Open Access Technology Inc (OATI)
Open Access Same-Time Information System
(OASIS)
102
Question 11
• Day-Ahead/Real-Time Schedules are created
in _____ and define the Operating Day,
Scheduled MWh, Asset Owner, Energy Type
and Transaction Type?
A.
B.
C.
D.
DART
Physical Scheduling System (PSS)
Open Access Technology Inc (OATI)
Open Access Same-Time Information System
(OASIS)
103
Question 12
• Market Settlements receives DayAhead/Real-Time schedule data from?
A.
B.
C.
D.
DART
Physical Scheduling System (PSS)
Open Access Technology Inc (OATI)
Open Access Same-Time Information System
(OASIS)
104
Settlement Statements Review
Settlements Overview
• Settlement is the process by which the MISO
determines what charges and credits MPs
have incurred.
• The MISO operates two distinct settlement
processes:
– Transmission Settlements
– Market Settlements
106
Transmission Settlements
•
Process that financially settles MPs’ use
of the MISO’s Transmission System and
mandated, non-competitive Ancillary
Services such as scheduling and voltage
support.
•
MP charges for transmission and
Ancillary Services are calculated based
on the Tariff that has been approved by
FERC.
•
The collected funds are distributed to
the Transmission Owners and the
providers of the mandated Ancillary
Services.
*For more detailed information on the MISO’s
Transmission Settlement process, please see the BPM for
Transmission Settlements.
107
TX Tariff Schedules
Ancillary Services
Schedule 1
Schedule 2
Scheduling, System Control and Dispatch Service
Reactive Supply and Voltage Control Service
Schedule 7
Schedule 8
Schedule 9
Schedule 26
Schedule 33
Firm Point-to-Point
Non-Firm Point-to-Point
Network Integration Transmission Service
Network Upgrade Charge from Transmission Expansion
Plan
Black Start
Schedule 10
Schedule 11
Schedule 20
Schedule 23
Schedule 35
MISO Cost Adder
Wholesale Distribution Service
Station Power
Recovery of Schedule 10 Costs from Certain GFAs
HVDC Cost Adder
Transmission Services
Additional Services
108
TX Monthly Settlement Process
• For Market Participants with charges due, the MISO
generates three invoices each month
• The Transmission Services invoice – TO Trust
• The Ancillary Services invoice – Non-TO Trust
• The Cost Adder invoice
• All invoices have terms of net seven (7) and are to be
provided in immediately available funds
• Payments received are distributed to the revenue
recipients within 24-48 hours
109
Transmission Settlement
Transmission Settlements Information Resources:
• BPM 012-Transmission Settlements
• BPM 017-Transimission Settlements Billing
Dispute Resolution
• BPM 020-Monthly Transmission Billing
•
http://www.midwestiso.org/Library/BusinessPracticesManuals/Pag
es/BusinessPracticesManuals.aspx
110
Market Settlements
•
The Market Settlements process financially
settles competitive transactional activities by
and between MPs within the MISO’s managed
Transmission System (i.e., market operations
footprint).
•
MP charges and credits resulting from the DayAhead, Financial Transmission Rights (FTRs),
and Real-Time Energy and Operating Reserve
Markets are calculated based on the Tariff.
•
Market Settlements of Physical Bilateral
Transactions is the process that will be
discussed throughout this presentation.
111
Market Settlements
Settlement Cycle
Cleared
Bids
Cleared
Offers
Charges
Settlements
Invoices
Disputes
Credits
Meter
Data
112
Statements and Invoice Definitions
• MISO provides the following to MPs:
– Settlement Statement
• Granular level of data by:
– Charge Type
– Asset Owner
– Interval
• Financially binding, but are not bills
– Summary Statement
• Aggregated data by:
– Settlement Statement Run, (S7, S14, S55, S105)
– Charge Type
– Invoice
• Weekly, financially binding, based on:
– Charges & Credits from previous weeks
113
Reconciling Settlement
and Summary Statements
Settlement 7
DA
RT
for OD 2/01/2011
FTR
Settlement 14
DA
RT
for OD 1/25/2011
FTR
Summary
02/08/11
DA
Settlement 55
RT
for OD 12/15/2010
FTR
DA
RT
FTR
Settlement 105
for OD 10/26/2010
•
One Summary Statement will be generated for each Execution Day per Asset Owner;
includes a summary of each of the Settlement Statements Executed for that Day
•
One Summary Statement will be generated for each Execution Day per Market Participant;
includes a summary of each of the Summary Statements Executed for that Day
114
Day-Ahead Charge Types
Day-Ahead Charges
Charge Type
Acronym
Type
Day-Ahead Non-Asset Energy Amount
DA_NASSET_EN
Energy
Day-Ahead Market Administration Amount
DA_ADMIN
Admin
Day-Ahead Schedule 24 Allocation Amount
DA_SCHD_24_ALC
Admin
Day-Ahead Revenue Sufficiency Guarantee Distribution
Amount
DA_RSG_DIST
Distribution
115
Real-Time Charge Types
Real-Time Charges
Charge Type
Acronym
Type
Real-Time Non-Asset Energy Amount
RT_NASSET_EN
Energy
Real-Time Market Administration Amount
RT Schedule 24 Allocation Amount
Real-Time Net Inadvertent Distribution
Real-Time Revenue Neutrality Uplift Amount
Spinning Reserve Cost Distribution Amount
RT_ADMIN
RT_SCHD_24_ALC
RT_NI_DIST
RT_RNU
RT_ASM_SPIN_DIST
Admin
Admin
Distribution
Distribution
Distribution
Supplemental Reserve Cost Distribution Amount
RT_ASM_SUPP_DIST
Distribution
Real-Time Revenue Sufficiency Guarantee First Pass
Distribution Amount
RT_RSG_DIST1
Distribution
116
Market Settlements
• Market Settlement Information Resources:
• BPM 005 Market Settlements
– MS-OP-029 Market Settlements Calculation Guide
– MS-OP-030 MISO Guide to FERC Electric Quarterly
Reporting
– MS-OP-031 Post Operating Processor Calculation
Guide
http://www.midwestiso.org/Library/BusinessPracticesManuals/Pages/B
usinessPracticesManuals.aspx
117
Physical Bilateral Settlement
Settlement Statements Review
•
•
•
•
•
Charge Types and Calculated Amounts location
Charge Type hourly calculation location
LMP location
Settlement Statements schedules location
Settlement Statement schedules examples
119
Settlement Statement
• The Statement Line Items section of the Settlement
Statement contains the charge types and the
calculated total amounts.
120
Settlement Statement
• The Hourly Settlement Amounts section of the
Settlement Statement contains the charge type and
total charge for each hour.
121
Settlement Statement
• The Market Wide Determinants section contains the
LMP.
122
Settlement Statement
• Settlement Statement Schedules are located in the
Asset Owner Determinants Section of the Settlement
Statement.
123
Settlement Statement
• Real-Time Import Schedule
– Source ABC is external and sink is internal to MISO.
– Transaction ID Type is WI which is Wheel In.
124
Settlement Statement
• Real-Time Export Schedule
– Source is internal and sink is DEF is external to MISO.
– Transaction ID Type is WO which is Wheel Out.
125
Settlement Statement
• Real-Time Through Schedule
– Have a Source (ABC) and Sink (DEF).
– A Source and Sink schedule will be on the Settlement
Statement.
– Transaction ID Type is WT which is Wheel Through.
126
Notification Dead Line (NDL)
Settlement Statement
•
•
As part of the RSG Redesign the Settlement Statement will have Physical
Bilateral Transaction Volumes at the Source and Sink and also Physical
Bilateral Transaction NDL Volumes at Source and Sink.
The NDL volume is submitted 4 hours prior to each Market Hour.
127
Settlement Sign Convention
Schedules
(+)
(-)
Physical Bilateral Transactions (PBT)
(Physical Schedules)
Buyer/Exports
Seller/Imports
Activity
(+)
(-)
Charges
Credits
Payment due
MISO
Payment due
MP
Settlement Statements
128
Summary
• LMP’s are calculated at external Commercial Pricing
Nodes to settle market activities.
• The Asset Owner Determinants, Market Wide
Determinants, Hourly Settlement Amounts sections are
use to calculate the total amounts for a particular charge
type in the Statement Line Items of a Settlement
Statement.
• Settlement Statement Schedules are located in the
Asset Owner Determinants Section of the Settlement
Statement.
129
Questions?
130
Review
Question 13
• This section of the Settlement Statement
contains the Charge Type and Calculated
Total Amounts?
A.
B.
C.
D.
Hourly Settlement Amounts
Statement Line Items
Market Wide Determinants
Asset Owner Determinants
132
Question 14
• The LMP for Import, Export and Through
Schedules is determined at the ____
commercial pricing nodes where energy is
being imported and exported from the MISO
market?
A.
B.
C.
D.
External Interface
Internal Interface
Import Interface
Export Interface
133
Question 15
• This section of the Settlement Statement
contains the LMP for each hour?
A.
B.
C.
D.
Hourly Settlement Amounts
Statement Line Items
Market Wide Determinants
Asset Owner Determinants
134
Question 16
• This section of the Settlement Statement
contains the Day-Ahead/Real-Time
Schedules?
A.
B.
C.
D.
Asset Owner Determinants
Statement Line Items
Market Wide Determinants
Hourly Settlement Amounts
135
Settlement Disputes
Settlement Disputes
• Common Reasons for Disputes
• Common Reasons Disputes get Denied/Rejected
• Procedure for filing a dispute is in the Market
Settlements Business Practice Manual and in the
Settlements Overview Training Presentation
137
Common Dispute Reasons
• Day-Ahead/Real-Time option not selected in OATI
• Day-Ahead Schedule rejected due to Market Clearing
results, but Market Adjustment denied by Counter-Party
resulting in schedule to flow in Real-Time
• Day-Ahead Schedule Adjustment entered after Market
closes
138
Common Dispute Reasons
• Real-Time Schedule has incorrect Asset Owner
assigned due to copying an old schedule.
• Real-Time Schedule curtailment for an operating
hour.
139
Day-Ahead/Real-Time Dispute
700 AM
EST
900 AM
EST
2/13/2011
•
•
• Market Participant creates a schedule HE1-HE5 75MW/h on
2/5/2011 for OD 2/6/2011 in OATI but only selects the Real-Time
Option or does not select any option.
• All parties approve the Schedule on 2/5/2011.
• The schedule is now implemented.
• Market Participant Reviews the S7 Settlement Statement and files a
dispute stating the Day-Ahead schedule is missing.
This dispute would be denied even though the schedule was submitted and
approved (OD-1) since the Day-Ahead/Real-Time option was not selected
in OATI.
The Settlement Statement would have a Real-Time Schedule HE1-HE5
75MW/h.
140
Day-Ahead/Real-Time Dispute
Real-Time Tag
Day-Ahead/Real-Time Tag
141
Day-Ahead/Real-Time Dispute
900 AM
EST
1030AM
EST
• Market Participant submits a Day-Ahead/Real-Time Schedule HE9-HE12
35MW/h on 2/3/2011 for OD 2/4/2011.
• All parties approve the schedule on 2/3/2011.
1500 PM
EST
• Market Clearing results posted and financial offer is to high.
• Tag is rejected and Market Adjusted to 0 MW HE9-HE12.
1510 PM
EST
• The Market Adjust is denied by counter-party.
• The schedule will then flow in Real-Time HE9-HE12 35MW.
2/11/2011
• Market Participant Reviews the S7 Settlement Statement and files a dispute
stating the Day-Ahead schedule should be HE9-HE12 35MW/h
•
•
This dispute would be denied since the denial of a Market
Adjustment does not change the clearing results.
The Settlement Statement would have 0MW HE9-12 for the DayAhead schedule and 35MW/h for the Real-Time schedule.
142
Day-Ahead/Real-Time
Adjustment Dispute
730 AM
EST
830 AM
EST
1101AM
EST
2/12/2011
•
•
• Market Participant submits Day-Ahead/Real-Time schedule HE1-HE10 50MW/h
on 2/4/2011 for OD 2/5/2011.
• All parties approve the schedule on 2/4/2011.
• The schedule is now implemented.
• Market Participant adjusts the schedule HE1-HE10 to 55MW/h on 2/4/2011.
• Market Participant Reviews the S7 Settlement Statement and files a dispute
stating the Day-Ahead schedule is incorrect and HE1-HE10 should be 55MW/h.
This dispute would be denied since the adjustment was after the Market
closing
The Settlement Statement would have a Day-Ahead schedule HE1-HE10
50MW/h and a Real-Time schedule HE1-HE10 55MW/h
143
Real-Time Asset Owner Dispute
500 AM
EST
730AM
EST
• Market Participant copies an old tag with asset owner ABCD assigned to the
TSR and submits a Real-Time Schedule HE8-HE10 20MW/h for OD
2/11/2011.
• All parties approve the schedule.
• The schedule is now implemented.
• Market Participant Reviews the S7 Settlement Statement and files a dispute
stating they copied an old tag and realized the asset owner is incorrect and it
should be DEFG.
2/18/2011
• This dispute would be denied since MISO applied the asset
owner per the TSR used.
144
Real-Time Curtailment Dispute
600 AM
EST
730AM
EST
1:00 PM
EST
2/16/2011
• Market Participant submits a Real-Time Schedule HE14-HE16 30MW/h for OD
2/9/2011.
• All Parties approve the Real-Time schedule on 2/9/2011.
• The Real-Time Schedule is now implemented.
• Due to reliability issues HE14 is curtailed to 20MW/h.
• Market Participant Reviews the S7 Settlement statement and files a dispute
stating the Real-Time schedule HE14 should be 30MW/h.
• This dispute would be denied since HE14 was curtailed to 20MW/h.
• The Settlement Statement would have a Real-Time schedule HE14
20 MW/h and HE15-HE16 30 MW/h.
145
Summary
• Main Reasons for Day-Ahead/Real-Time disputes
–
–
–
Real-Time or no option selected for a Day-Ahead/Real-Time schedule.
Market Clearing results cause Day-Ahead/Real-Time schedule to be
Market Adjusted to 0 MW which is then denied by a counter party
causing the schedule to flow in Real-Time.
Day-Ahead/Real-Time schedule adjusted after market closing.
• Main Reasons for Real-Time disputes
–
–
–
Schedules not beginning at the top, quarter past, half past or quarter till
the hour.
Schedules being submitted or modified during the operating hour.
Difference in volume after a curtailment
146
Questions?
147
Break
148
Physical Bilateral Transactions
Charge Types
Day-Ahead Charge Types
Day-Ahead Charges
Charge Type
Acronym
Type
Day-Ahead Non-Asset Energy Amount
DA_NASSET_EN
Energy
Day-Ahead Market Administration Amount
DA_ADMIN
Admin
Day-Ahead Schedule 24 Allocation Amount
DA_SCHD_24_ALC
Admin
Day-Ahead Revenue Sufficiency Guarantee Distribution
Amount
DA_RSG_DIST
Distribution
150
Day-Ahead Physical Schedule
Scenarios
• Export Schedule – 150 MW schedule for HE1 which was
approved before 11:00 AM (OD-1) but adjusted to 125 MW by MISO.
• Import Schedule – 100 MW scheduled for HE1 which was
approved before 11:00 AM (OD-1) but adjusted to 80 MW by
MISO.
• Through Schedule – 100 MW scheduled for HE1 which was
approved before 11:00 AM (OD-1) and no adjustments made.
151
Day-Ahead Physical Schedule
Scenarios
Import Schedule
MISO Market
HE1 Scheduled 100 MW
Approved before 11:00 AM (OD-1)
HE1 Adjusted to 80 MW by MISO
Source
$20
LMP
Source
Sink
Export Schedule
HE1 Scheduled 150 MW
Approved before 11:00 AM (OD-1)
HE1 Adjusted to 125 MW by MISO
$30
LMP
Source
Sink
$15
LMP
$10
LMP
Sink
Through Schedule
HE1 Scheduled 100 MW
Approved before 11:00 AM (OD-1)
HE1 No Adjustments Made
152
Day-Ahead Non-Asset
Energy Amount (DA_NASSET_EN)
DA_NASSET_EN - Purpose
• Day-Ahead Non-Asset Energy Amount (DA_NASSET_EN)
• Represents the AO’s daily Day-Ahead net energy cost (or credit) related
to Commercial Pricing Nodes where the AO does not own assets for
that Operating Day.
• Energy is purchased at the transaction source CPNode.
• Energy is sold at the transaction sink CPNode.
• Includes Physical Bilateral Transactions (PBT), Financial Bilateral
Transactions (FBT) and Carved-Out Grandfathered Transactions.
Who gets the
charge/credit?
• Asset Owner Buyer
• Asset Owner Seller
Where does it
come or go?
• Load/Generating Serving Entities which
do not own any Asset in MISO Market
154
DA_NASSET_EN - Hierarchy
155
DA_NASSET_EN - Formula
*DA_NASSET_EN
=∑
H
*DA_NASSET_EN_HR
=
(
*DA_NASSET_EN_HR
= ∑ cn( DA _ NASSET _ VOL * DA _ LMP _ EN ) + [( DA _ PHYSHVDC * DA _ LMP _ ENHVDC _ SRC )
− ( DA _ PHYSHVDC * DA _ LMP _ ENHVDC _ SNK )]
Determinant
DA_NASSET_VOL
*DA_LMP_EN
)
Formula
= DA_PHYS_VOLBuyer + DA_PHYS_VOLSeller + DA_FIN_NASSET_VOLSeller+
DA_FIN_NASSETBuyer +DA_GFACO_NASSET_VOLSeller +
DA_GFACO_NASSET_VOLBuyer
Hourly Day-Ahead LMP ($/MWh)
*DA_PHYSHVDC
Hourly Day-Ahead PBT Volume where the AO is wheeling energy across a HVDC
transmission line.
*DA_LMP_ENHVDC_SRC
Hourly Day-Ahead LMP ($/MWh) at a Commercial Pricing Node which is the source of the
HVDC transaction.
*DA_LMP_ENHVDC_SNK
Hourly Day-Ahead LMP ($/MWh) at a Commercial Pricing Node which is the sink of the
HVDC transaction.
156
DA_NASSET_EN
Import Schedule.
• HE1 100 MW was scheduled but adjusted to 80 MW by MISO.
• LMP is $30 at the external CPNode where energy being imported
into MISO.
• What is the charge/credit for DA_NASSET_EN?
DA_NASSET_EN
HE DA_PHYS_ DA_PHYS_
1
DA_FIN_
DA_FIN_
DA_GFACO_
DA_GFACO_
VOL
VOL
NASSET_VOL
NASSET_VOL
Buyer
Seller
Seller
Buyer
Seller
Buyer
0
-80
0
0
0
0
*DA_LMP_EN
NASSET_VOL NASSET_VOL
$30
157
DA_NASSET_EN
Intermediate Calculations
Determinant
Formula
= DA_PHYS_VOLBuyer + DA_PHYS_VOLSeller + DA_FIN_NASSET_VOLSeller +
DA_FIN_NASSET_VOLBuyer + DA_GFACO_NASSET_VOLSeller +
DA_GFACO_NASSET_VOLBuyer
DA_NASSET_VOL
-80
DA_LMP_EN
=Σ(0 +(-80) + 0 + 0 + 0 + 0)
Hourly Day-Ahead LMP ($/MWh)
$30
DA_PHYSHVDC
Hourly DA PBT Volume where AO is wheeling energy across HVDC transmission line.
DA_LMP_ENHVDC_SRC
Hourly Day-Ahead LMP ($/MWh) at a Commercial Pricing Node, which is the source of
HVDC transaction.
DA_LMP_ENHVDC_SNK
Hourly Day-Ahead LMP ($/MWh) at a Commercial Pricing Node, which is the source of
HVDC transaction.
158
DA_NASSET_EN
*DA_NASSET_EN_HR
=∑
=∑
CN
$-2,400.00
H
(
*DA_NASSET_VOL
x
(
-80
x
*DA_LMP_EN
$30.00
)
)
Credit
159
DA_NASSET_EN
*DA_NASSET_EN
=∑
(
*DA_NASSET_EN_HR
)
=∑
(
$-2,400.00
)
H
$-2,400.00
H
Results in a $-2,400.00 credit for HE 1
160
DA_NASSET_EN
Export Schedule
• HE1 150 MW was scheduled but adjusted to 125 MW by MISO.
• LMP is $20 at the external CPNode where energy is being
exported out of MISO.
• What is the charge/credit for DA_NASSET_EN?
DA_NASSET_EN
HE
1
DA_PHYS_
DA_PHYS_
DA_FIN_
DA_FIN_
DA_GFACO_
DA_GFACO_
*DA_LMP
VOL
VOL
NASSET_VOL
NASSET_VOL
NASSET_VOL
NASSET_VOL
_EN
Buyer
Seller
Seller
Buyer
Seller
Buyer
125
0
0
0
0
0
$20
161
DA_NASSET_EN
Intermediate Calculations
Determinant
Formula
= DA_PHYS_VOLBuyer + DA_PHYS_VOLSeller + DA_FIN_NASSET_VOLSeller +
DA_FIN_NASSET_VOLBuyer + DA_GFACO_NASSET_VOLSeller +
DA_GFACO_NASSET_VOLBuyer
DA_NASSET_VOL
125
DA_LMP_EN
=Σ(125 +0+ 0 + 0 + 0 + 0)
Hourly Day-Ahead LMP ($/MWh)
$20
DA_PHYSHVDC
Hourly DA PBT Volume where AO is wheeling energy across HVDC transmission line.
DA_LMP_ENHVDC_SRC
Hourly Day-Ahead LMP ($/MWh) at a Commercial Pricing Node, which is the source of
HVDC transaction.
DA_LMP_ENHVDC_SNK
Hourly Day-Ahead LMP ($/MWh) at a Commercial Pricing Node, which is the source of
HVDC transaction.
162
DA_NASSET_EN
*DA_NASSET_EN_HR
=∑
=∑
CN
$2,500
H
(
*DA_NASSET_VOL
x
(
125
x
*DA_LMP_EN
$20.00
)
)
Charge
163
DA_NASSET_EN
*DA_NASSET_EN
=∑
(
*DA_NASSET_EN_HR
)
=∑
(
$2,500.00
)
H
$2,500.00
H
Results in a $2,500.00 charge for HE 1
164
DA_NASSET_EN
Wheel Through Schedule
• HE1 100 MW was scheduled and no adjustments.
• LMP is $15 at the external CPNode where energy is being
imported into MISO.
• LMP is $10 at the external CPNode where energy is being
exported out of MISO.
• What is the charge/credit for DA_NASSET_EN?
DA_NASSET_EN
HE DA_PHYS_VOL DA_PHYS_VO
Buyer
DA_FIN_
DA_FIN_
DA_GFACO_
DA_GFACO_
*DA_LMP
L
NASSET_VOL
NASSET_VOL
NASSET_VOL
NASSET_VOL
_EN
Seller
Seller
Buyer
Seller
Buyer
1
0
-100
0
0
0
0
$15
1
100
0
0
0
0
0
$10
165
DA_NASSET_EN
Intermediate Calculations –Wheel Through Schedule - Import
Determinant
Formula
= DA_PHYS_VOLBuyer + DA_PHYS_VOLSeller + DA_FIN_NASSET_VOLSeller +
DA_FIN_NASSET_VOLBuyer + DA_GFACO_NASSET_VOLSeller +
DA_GFACO_NASSET_VOLBuyer
DA_NASSET_VOL
-100
DA_LMP_EN
=Σ(0 + (-100)+ 0 + 0 + 0 + 0)
Hourly Day-Ahead LMP ($/MWh)
$15
DA_PHYSHVDC
Hourly DA PBT Volume where AO is wheeling energy across HVDC transmission line.
DA_LMP_ENHVDC_SRC
Hourly Day-Ahead LMP ($/MWh) at a Commercial Pricing Node, which is the source of
HVDC transaction.
DA_LMP_ENHVDC_SNK
Hourly Day-Ahead LMP ($/MWh) at a Commercial Pricing Node, which is the source of
HVDC transaction.
166
DA_NASSET_EN
*DA_NASSET_EN_HR
=∑
=∑
CN
$-1,500.00
H
(
*DA_NASSET_VOL
x
(
-100
x
*DA_LMP_EN
$15.00
)
)
Credit
167
DA_NASSET_EN
*DA_NASSET_EN
=∑
(
*DA_NASSET_EN_HR
)
=∑
(
$-1,500.00
)
H
$-1,500.00
H
Results in a $-1,500.00 credit for HE 1
168
DA_NASSET_EN
Intermediate Calculations –Wheel Through Schedule - Export
Determinant
Formula
= DA_PHYS_VOLBuyer + DA_PHYS_VOLSeller + DA_FIN_NASSET_VOLSeller +
DA_FIN_NASSET_VOLBuyer + DA_GFACO_NASSET_VOLSeller +
DA_GFACO_NASSET_VOLBuyer
DA_NASSET_VOL
100
DA_LMP_EN
=Σ(100 +0+ 0 + 0 + 0 + 0)
Hourly Day-Ahead LMP ($/MWh)
$10
DA_PHYSHVDC
Hourly DA PBT Volume where AO is wheeling energy across HVDC transmission line.
DA_LMP_ENHVDC_SRC
Hourly Day-Ahead LMP ($/MWh) at a Commercial Pricing Node, which is the source of
HVDC transaction.
DA_LMP_ENHVDC_SNK
Hourly Day-Ahead LMP ($/MWh) at a Commercial Pricing Node, which is the source of
HVDC transaction.
169
DA_NASSET_EN
*DA_NASSET_EN_HR
=∑
=∑
CN
$1,000.00
H
(
*DA_NASSET_VOL
x
(
100
x
*DA_LMP_EN
$10.00
)
)
Charge
170
DA_NASSET_EN
*DA_NASSET_EN
=∑
(
*DA_NASSET_EN_HR
)
=∑
(
$1,000.00
)
H
$1,000.00
H
Results in a $1,000.00 charge for HE 1
171
DA_NASSET_EN
*DA_NASSET_EN
=∑
(
=∑
(
H
$-500
H
*DA_NASSET_EN_HR Seller
$-1,500
-
-
*DA_NASSET_EN_HR Buyer
)
)
$1,000
Total Wheel Through Schedule Credit HE1 is $-500.00
172
DA_NASSET_EN - Total
DA_NASSET_EN
$-400
=
=
Import Schedule
$-2,400 Credit
-
-
Export Schedule
$2,500 charge
+
+
Through Schedule
$-500 Credit
Results in a $-400.00 credit for HE 1
173
DA_NASSET_EN – Summary
The Day-Ahead Non-Asset Energy Amount is the product of
(1) the sum of
(a) Cleared Day-Ahead energy schedules,
(b) Day-Ahead Financial Bilateral Transactions,
(c) Day-Ahead Carve Out Grandfathered Agreement
Transactions; and
(2) the LMP
at each Commercial Pricing Node where the AO does
not own Load Purchases and Generator Sales for an
Asset.
Questions?
174
Day-Ahead Market Administration
Amount (DA_ADMIN)
DA_ADMIN - Purpose
• Day-Ahead Market Administration Amount (DA_ADMIN)
•
•
•
Collectively referred to as Tariff Schedule 17, the DA_ADMIN and RT_ADMIN
charge types are designed to recover the MISO cost of operating the DayAhead and Real-Time Energy and Operating Reserves Markets
Calculated at each CPNode for each hour by multiplying an AO’s Day-Ahead
Market participation volume by the Hourly Energy and Operating Reserve
Markets Administration Rate
An AO’s DA participation volume at a CPNode is based on the total directional
energy volume into and out of the CPNode, by the AO
Who gets the
charge?
Where does it
go?
• AOs with cleared schedules
originating or terminating at a CPNode
in the Day-Ahead Market
• To the MISO to recover the cost of
operating the Day-Ahead Energy and
Operating Reserve Market
176
DA_ADMIN - Hierarchy
177
DA_ADMIN - Formula
*DA_ADMIN
*DA_ADMIN_VOL
Determinant
=
∑(
=∑
H
*DA_ADMIN_VOL
x
(
CN
)
*DART_ADMIN_RATE
DA_NET_SELL_ADMIN + DA_NET_SELL_ADMIN_INT +
DA_NET_BUY_ADMIN + DA_NET_BUY_ADMIN_INT +
DA_VSCHD_VOL
)
Formula
DA_NET_SELL_ADMIN
An AO's Hourly Admin Volume from Cleared DA Schedules, selling FBTs, and Carve-Out
GFA Transactions at Non-Interface CPNodes (MWh)
DA_NET_SELL_ADMIN_INT
An AO's Hourly Admin Volume from Cleared DA Schedules, selling FBTs, PBTs, and
Carve-Out GFA Transactions at Interface CPNodes (MWh)
DA_NET_BUY_ADMIN
An AO's Hourly Admin Volume from Cleared DA Schedules, buying FBTs, and Carve-Out
GFA Transactions at Non-Interface CPNodes (MWh)
DA_NET_BUY_ADMIN_INT
An AO's Hourly Admin Volume from Cleared DA Schedules, buying FBTs, PBTs, and
Carve-Out GFA Transactions at Interface CPNodes (MWh)
DA_VSCHD_VOL
The Hourly Day-Ahead Net Virtual Schedule Volume at a CPNode for an AO (MWh)
178
DA_ADMIN - Formula
*DA_ADMIN_VOL
=∑
(
CN
DA_NET_SELL_ADMIN + DA_NET_SELL_ADMIN_INT +
DA_NET_BUY_ADMIN + DA_NET_BUY_ADMIN_INT +
DA_VSCHD_VOL
Determinant
)
Formula
DA_NET_SELL_ADMIN
= MAX {ABS [MIN ( 0 , DA_SCHD ) ] ,
[ Σ (DA_FINSeller) + Σ (DA_GFAOBSeller) + Σ (DA_GFACOSeller ) ] }
DA_NET_SELL_ADMIN_INT
= MAX {[ Σ ( DA_FINSeller ) + Σ ( DA_GFAOBSeller ) ] ,
Σ ( DA_PHYSSeller ) } + Σ ( DA_GFACOSeller )
DA_NET_BUY_ADMIN
= MAX { MAX ( 0 , DA_SCHD ),
[ Σ (DA_FINBuyer) + Σ (DA_GFAOBBuyer) + Σ (DA_GFACOBuyer) ] }
DA_NET_BUY_ADMIN_INT
= MAX { [ Σ ( DA_FINBuyer ) + Σ ( DA_GFAOBBuyer ) ] ,
Σ ( DA_PHYSBuyer ) } + Σ ( DA_GFACOBuyer )
DA_VSCHD_VOL
= Σ [ ABS ( DA_VSCHD ) ]
179
DA_ADMIN – Schedule 17 Rate
• The Schedule 17 Rate is updated on or near the first of each
month.
• Rate updates can be found on the MISO Website > Market and
Operations > Notifications > View Market Settlement Updates >
Then Month and Year for the rates.
180
DA_ADMIN Example
Scenario
• Import Schedule HE1 100 MW was scheduled but adjusted to 80
MW by MISO.
• Export Schedule HE1 150 MW was scheduled but adjusted to 125
MW by MISO.
• Wheel Through Schedule HE1 100 MW was scheduled and no
adjustments.
• What is the charge/credit for DA_ADMIN?
DA_ADMIN
HE
1
*DA_PHYS
*DA_PHYS
Seller
Buyer
180
225
*DART_ADMIN_RATE
$.098
181
DA_ADMIN Example
Determinant
Formula
= MAX {ABS [MIN ( 0 , DA_SCHD ) ] ,[ Σ (DA_FINSeller) + Σ (DA_GFAOBSeller) +
Σ (DA_GFACOSeller ) ] }
DA_NET_SELL_ADMIN
DA_NET_SELL_ADMIN_INT
180
= MAX {[ Σ ( DA_FINSeller ) + Σ ( DA_GFAOBSeller ) ] ,
Σ ( DA_PHYSSeller ) } + Σ ( DA_GFACOSeller )
=MAX{[0 + 0],180} + 0)
DA_NET_BUY_ADMIN
= MAX { MAX ( 0 ,
DA_NET_BUY_ADMIN_INT
= MAX { [ Σ ( DA_FINBuyer ) + Σ ( DA_GFAOBBuyer ) ] ,
Σ ( DA_PHYSBuyer ) } + Σ ( DA_GFACOBuyer )
DA_SCHD ),
[ Σ (DA_FINBuyer) + Σ (DA_GFAOBBuyer) + Σ (DA_GFACOBuyer) ] }
225
DA_VSCHD_VOL
=MAX{[0 + 0], 225 + 0)
= Σ [ ABS ( DA_VSCHD ) ]
182
DA_ADMIN –Example
Charge Type Calculation
*DA_ADMIN_VOL
405 MW
*DA_ADMIN
$39.69
=∑
(
= ∑ ( 0 + 180 + 0 + 225 + 0 )
CN
DA_NET_SELL_ADMIN + DA_NET_SELL_ADMIN_INT +
DA_NET_BUY_ADMIN + DA_NET_BUY_ADMIN_INT +
DA_VSCHD_VOL
)
CN
=
∑(
*DA_ADMIN_VOL
=
∑(
405 MW
H
H
x
x
*DART_ADMIN_RATE
$.098
)
)
Results in a $39.69 charge for HE 1
183
DA_ADMIN – Summary
• The Day-Ahead Market Administration Amount is calculated by
multiplying an AO’s DA participation volume by the Market
Administration Rate.
• This charge type is designed to recover the MISO cost of operating
the Day-Ahead and Real-Time Energy and Operating Reserves
Markets under Tariff Schedule 17.
• In accordance with the Tariff, all assets meeting the administrative
charge exemption are not subject to the Day-Ahead Market
Administrative Amount charge type.
• All transactions and schedules that are not exempt, originating at, or
terminating at a CPNode are subject to this charge type.
Questions?
184
Day-Ahead Schedule 24 Allocation
Amount (DA_SCHD_24_ALC)
DA_SCHD_24_ALC - Purpose
• Day-Ahead Schedule 24 Allocation Amount (DA_SCHD_24_ALC)
•
•
•
Cost mechanism by which Local Balancing Authorities recover the cost of
labor and material associated with market operations
Calculated by multiplying the DA Administrative volume by the Schedule 24
Rate to obtain an hourly dollar amount
An AO’s DA participation volume at a CPNode is based on the total cleared
energy volume for each CPNode, by the AO
Who gets the
charge?
• Asset Owners participating in the DayAhead Energy and Operating Reserve
Market
Where does it go?
• Used to fund Schedule 24 distribution
back to the LBAs
186
DA_SCHD_24_ALC - Hierarchy
187
DA_SCHD_24_ALC - Formula
*DA_SCHD_24_ALC
=∑
H
(
*DA_ADMIN_VOL
x
*SCHD_24_ALC_RATE
)
Day-Ahead Market Administration Volume for an AO (MWh)
*DA_ADMIN_VOL
=
See DA_ADMIN Charge Type
Hourly Schedule 24 Allocation Rate ($/MWh)
*SCHD_24_ALC_RATE
=
in
• LBAs submit the previous year’s applicable costs to the MISO by May 1st
st
st
order to calculate the rate(s) for the upcoming Schedule year (June 1 - May 31 ).
• The allocation rate is published for each calendar month.
188
DA_SCHD – Schedule 24 Rate
• The Schedule 24 Rate is updated on or near the first of each
month.
• Rate updates can be found on the MISO Website > Market and
Operations > Notifications > View Market Settlement Updates >
Then the Month and Year for the rates.
189
DA_SCHD_24_ALC Example
Scenario
• Using the information from the DA_ADMIN example the
DA_ADMIN_VOL is 405 MW.
• What is the charge/credit for DA_SCHD_24_ALC?
DA_SCHD_24_ALC
HE
*DA_ADMIN_VOL
*SCHD_24_ALC_RATE
1
405
$.011
190
DA_SCHD_24_ALC Example
Charge Type Calculation
*DA_SCHD_24_ALC
=∑
H
$4.46
(
*DA_ADMIN_VOL
=∑
H
( 405 MW
x
*SCHD_24_ALC_RATE
x
$.011
)
)
Results in a $4.46 charge for HE 1
191
DA_SCHD_24_ALC – Summary
• The DA Schedule 24 Allocation Amount constitutes the collected
monies, in the Day-Ahead Market, used to fund Schedule 24
distribution back to the LBAs and is calculated by multiplying the DA
Admin Volume by the Schedule 24 Rate.
• The aggregation of Day-Ahead and Real-Time Allocation amounts
is equal to the full daily distribution of Schedule 24 funds back to
the LBAs.
Questions?
192
Day-Ahead Revenue Sufficiency
Guarantee Distribution Amount
(DA_RSG_DIST)
DA_RSG_DIST - Purpose
• Day-Ahead Revenue Sufficiency Guarantee Distribution
Amount (DA_RSG_DIST)
• This charge funds the Day Ahead Make Whole Payments paid to the
generation asset owners
• Charges load asset owners for a portion of the total market wide
Make Whole Payment amount based on the percentage of their load
to the overall market load
Who gets the
charge?
Where does it go?
• Asset Owners with Load, Virtual
Schedules and/or Exports
• Asset Owners with cleared Energy
Offers (via Make Whole Payment)
194
DA_RSG_DIST – Hierarchy
195
DA_RSG_DIST - Formula
*DA_RSG_DIST
=∑
((
H
*MISO_DA_RSG_MWP
x
DA_RSG_DIST_FCT
)x(-1))
Hourly MISO Day-Ahead RSG MWP Amount ($)
*MISO_DA_RSG_MWP
=
ΣMISO ( DA_RSG_MWP_HR )
Hourly Day-Ahead RSG Distribution Factor by AO (factor)
DA_RSG_DIST_FCT
=
( DA_RSG_DIST_VOLAO / MISO_DA_RSG_DIST_VOL )
= DA_ASSET_DEMD + DA_VIRT_DEMD + DA_PHYS_EXP
196
DA_RSG_DIST – Formula
Intermediate Calculations
Hourly Day-Ahead RSG Distribution Factor by AO (factor)
DA_RSG_DIST_FCT
=
( DA_RSG_DIST_VOL / MISO_DA_RSG_DIST_VOL )
= DA_ASSET_DEMD + DA_VIRT_DEMD + DA_PHYS_EXP
Determinant
Formula
= ΣAO-CN MAX { [ MAX (DA_SCHD, 0 ) - ΣTransactions ( DA_GFACOBuyer) ] , 0 }
DA_ASSET_DEMD
* IF { DA_RSG_DIST_XMPT = “Y”, THEN 0, ELSE 1 }
= ΣCN [ MAX ( DA_VSCHD, 0 ) ]
DA_VIRT_DEMD
* IF { DA_RSG_DIST_XMPT = “Y”, THEN 0, ELSE 1 }
= ΣTransactions [ MAX ( DA_PHYS_TRNS, 0 ) ]
DA_PHYS_EXP
DA_PHYS_TRNS = DA_PHYSBuyer + [ DA_PHYSSeller x (-1) ]
197
DA_RSG_DIST - Example
Scenario
• Import Schedule HE1 100 MW was scheduled but adjusted to 80 MW
by MISO.
• Export Schedule HE1 150 MW was scheduled but adjusted to 125 MW
by MISO.
• Wheel Through Schedule HE1 100 MW was scheduled and no
adjustments.
• HE1 MISO Day-Ahead RSG MWP Amount is -$9,000.
• HE1 MISO Day-Ahead RSG Distribution Volume is 40,000 MW.
• What is the charge/credit for DA_RSG_DIST?
DA_RSG_DIST
HE
1
*DA_PHYSBuyer
125
*DA_PHYSSeller
0
*MISO_DA_RSG_
*MISO_DA_RSG_DIST
MWP
_VOL
-$9,000
40,000
198
DA_RSG_DIST - Example
Intermediate Calculations
Determinant
Formula
DA_ASSET_DEMD
= ΣAO-CN MAX { [ MAX (DA_SCHD, 0 ) - ΣTransactions ( DA_GFACOBuyer) ] , 0 }
DA_VIRT_DEMD
= ΣAO-CN MAX { [ MAX ( 0, 0 ) - ΣTransactions ( 0 ) ] , 0 }
= ΣCN [ MAX ( DA_VSCHD, 0 ) ]
* IF { DA_RSG_DIST_XMPT = “Y”, THEN 0, ELSE 1 }
DA_PHYS_EXP
DA_RSG_DIST_FCT
= ΣCN [ MAX ( 0, 0 ) ]
* IF { DA_RSG_DIST_XMPT = “Y”, THEN 0, ELSE 1 }
= ΣTransactions [ MAX ( DA_PHYS_TRNS, 0 ) ]
*DA_PHYS_TRNS = DA_PHYSBuyer + [ DA_PHYSSeller x (-1) ]
DA_PHYS_TRANS = 125 + [0 X -1]
125
=
( DA_RSG_DIST_VOL / MISO_DA_RSG_DIST_VOL )
= DA_ASSET_DEMD + DA_VIRT_DEMD + DA_PHYS_EXP
.0031
=
(125 /40,000)
= 0 MW + 0 MW + 125
199
DA_RSG_DIST – Example
Charge Type Calculation
*DA_RSG_DIST
=∑
*MISO_DA_RSG_MWP
x
DA_RSG_DIST_FCT
=∑
-$9,000
x
.0031
((
H
$27.90
((
H
)x(-1))
)x(-1))
Results in a $27.90 charge for HE 1
200
DA_RSG_DIST – Summary
• The Day-Ahead Revenue Sufficiency Guarantee Distribution
Amount funds the Make Whole Payments paid to the generation
asset owners.
• This charge type issues a charge to Load AOs for a portion of the
total market-wide Make Whole Payment amount based on the
percentage of their Load to the overall market Load.
• This amount is calculated hourly for an AO by multiplying the MISO
Day-Ahead RSG MWP Amount times the Day-Ahead RSG
Distribution Factor for that AO to arrive at their proportional share of
the DA RSG MWP.
Questions?
201
Day-Ahead Credits and Charges
Day-Ahead Credits and Charges
Charge Type
Schedule Type
Credit Amount
Charge Amount
$-400.00
$0.00
$0.00
$39.69
DA_ADMIN
Import, Export and Wheel
Trough
Import, Export and Wheel
Trough
DA_SCHD_24_ALC
Import, Export and Wheel
Trough
$0.00
$4.46
DA_RSG_DIST
Import, Export and Wheel
Trough
$0.00
$27.90
Total Credits/Charges
$-400.00
$71.75
Result - Credit
$-328.25
DA_NASSET_EN
202
Real-Time Charge Types
Real-Time Physical Schedule
Scenarios
• Export Schedule – 150 MW schedule for HE1 which was
approved before 11:00 AM (OD-1) but adjusted to 125 MW in DayAhead by MISO and then curtailed to 100 MW in Real-Time
• Import Schedule – 100 MW scheduled for HE1 which was
approved before 11:00 AM (OD-1) but adjusted to 80 MW in DayAhead by MISO and then increased back to 100 MW by Market
Participant in Real-Time
• Through Schedule – 100 MW scheduled for HE1 which was
approved before 11:00 AM (OD-1) and no adjustments made.
204
Real-Time Example Settlement Data
Import Schedule
MISO Market
Export Schedule
HE1 Increased back to 100 MW
by MP
HE1 curtailed to 100 MW
Source
$22
LMP
Source
Sink
$27
LMP
Source
Sink
$12
LMP
$17
LMP
Through Schedule
Sink
HE1 No Adjustments Made
205
Real-Time Charge Types
Real-Time Charges
Charge Type
Acronym
Type
Real-Time Non-Asset Energy Amount
RT_NASSET_EN
Energy
Real-Time Market Administration Amount
RT Schedule 24 Allocation Amount
Real-Time Net Inadvertent Distribution
Real-Time Revenue Neutrality Uplift Amount
Spinning Reserve Cost Distribution Amount
RT_ADMIN
RT_SCHD_24_ALC
RT_NI_DIST
RT_RNU
RT_ASM_SPIN_DIST
Admin
Admin
Distribution
Distribution
Distribution
Supplemental Reserve Cost Distribution Amount
RT_ASM_SUPP_DIST
Distribution
Real-Time Revenue Sufficiency Guarantee First Pass
Distribution Amount
RT_RSG_DIST1
Distribution
206
Real-Time Non-Asset Energy Amount
(RT_NASSET_EN)
RT_NASSET_EN - Purpose
• Real-Time Non-Asset Energy Amount (RT_NASSET_EN)
• Represents the AO’s daily Real-Time net energy cost (or credit) related
to Commercial Pricing Nodes where the AO does not own generation,
load, or DRR assets for the Operating Day.
• Energy is purchased at the transaction source CPNode.
• Energy is sold at the transaction sink CPNode.
• Includes Physical Bilateral Transactions (PBT), Financial Bilateral
Transactions (FBT) and Carved-Out Grandfathered Transactions.
Who gets the
charge/credit?
• Asset Owner Buyer
• Asset Owner Seller
Where does it
go?
• Load/Generating Serving Entities which
do not own any Asset in MISO Market
208
RT_NASSET_EN - Hierarchy
209
RT_NASSET_EN - Formula
*RT_NASSET_EN
=∑
H
=
*RT_NASSET_EN_HR
=
∑
(
cn
*RT_NASSET_EN_HR
)
( RT _ NASSET _ VOL * RT _ LMP _ EN )
+ [( RT _ PHYSHVDC − DA _ PHYSHVDC ) * RT _ LMP _ ENHVDC
− [( RT _ PHYSHVDC − DA _ PHYSHVDC ) * RT _ LMP _ ENHVDC
Determinant
_ SRC
_ SNK
]
]
Formula
= RT_PHYS_VOLNet - DA_PHYS_VOLNet + RT_FIN__VOLNet + RT_GFACO_VOLNet –
RT_NASSET_VOL
DA_GFACO_VOLNet
*RT_LMP_EN
Hourly Real-Time LMP ($/MWh)
*RT_PHYSHVDC
Hourly Real-Time PBT Volume where the AO is wheeling energy across a HVDC
transmission line.
*DA_PHYSHVDC
Hourly Day-Ahead PBT Volume where the AO is wheeling energy across a HVDC
transmission line.
*RT_LMP_ENHVDC_SRC
Hourly Real-Time LMP ($/MWh) at a Commercial Pricing Node which is the source of the
HVDC transaction.
*RT_LMP_ENHVDC_SNK
Hourly Real-Time LMP ($/MWh) at a Commercial Pricing Node which is the sink of the
HVDC transaction.
210
RT_NASSET_EN
Import Schedule
•
HE1 Cleared 80 MW in Day-Ahead Market increased back to 100 MW in
Real-Time Market.
•
LMP is $27 at the external CPNode where energy being imported into
MISO.
•
What is the charge/credit for RT_NASSET_EN?
RT_NASSET_EN
HE
1
RT_PHYS_
DA_PHYS_
RT_FIN_
RT_GFACO_
DA_GFACO_
VOLNet
VOLNet
VOLNet
VOLNet
VOLNet
-100
-80
0
0
0
*RT_LMP_EN
$27
211
RT_NASSET_EN
Intermediate Calculations -Import Schedule
Determinant
Formula
= RT_PHYS_VOLNet - DA_PHYS_VOLNet + RT_FIN__VOLNet + RT_GFACO_VOLNet –
RT_NASSET_VOL
DA_GFACO_VOLNet
-20
*RT_LMP_EN
= (-100) – (-80) + 0 + 0 + 0
Hourly Real-Time LMP ($/MWh)
27
*RT_PHYSHVDC
Hourly Real-Time PBT Volume where the AO is wheeling energy across a HVDC
transmission line.
*DA_PHYSHVDC
Hourly Day-Ahead PBT Volume where the AO is wheeling energy across a HVDC
transmission line.
*RT_LMP_ENHVDC_SRC
Hourly Real-Time LMP ($/MWh) at a Commercial Pricing Node which is the source of the
HVDC transaction.
*RT_LMP_ENHVDC_SNK
Hourly Real-Time LMP ($/MWh) at a Commercial Pricing Node which is the sink of the
HVDC transaction.
212
RT_NASSET_EN
*RT_NASSET_EN_HR
=∑
=∑
CN
$-540
H
(
*RT_NASSET_VOL
x
(
-20
x
*RT_LMP_EN
$27.00
)
)
Credit
213
RT_NASSET_EN
*RT_NASSET_EN
=∑
(
*RT_NASSET_EN_HR
)
=∑
(
$-540
)
H
$-540
H
Results in a $-540.00 Credit for HE 1 for Import Schedule
214
RT_NASSET_EN
Export Schedule
•
HE1 cleared125 MW in Day-Ahead Market then curtailed to 100 MW in
Real-Time Market.
•
LMP is $22 at the external CPNode where energy being exported out of
MISO.
•
What is the charge/credit for RT_NASSET_EN?
RT_NASSET_EN
HE
1
RT_PHYS_
DA_PHYS_
RT_FIN_
RT_GFACO_
DA_GFACO_
VOLNet
VOLNet
VOLNet
VOLNet
VOLNet
100
125
0
0
0
*RT_LMP_EN
$22
215
RT_NASSET_EN
Intermediate Calculations - Export Schedule
Determinant
Formula
= RT_PHYS_VOLNet - DA_PHYS_VOLNet + RT_FIN__VOLNet + RT_GFACO_VOLNet –
RT_NASSET_VOL
DA_GFACO_VOLNet
-25
*RT_LMP_EN
= 100 – 125 + 0 + 0 + 0
Hourly Real-Time LMP ($/MWh)
22
*RT_PHYSHVDC
Hourly Real-Time PBT Volume where the AO is wheeling energy across a HVDC
transmission line.
*DA_PHYSHVDC
Hourly Day-Ahead PBT Volume where the AO is wheeling energy across a HVDC
transmission line.
*RT_LMP_ENHVDC_SRC
Hourly Real-Time LMP ($/MWh) at a Commercial Pricing Node which is the source of the
HVDC transaction.
*RT_LMP_ENHVDC_SNK
Hourly Real-Time LMP ($/MWh) at a Commercial Pricing Node which is the sink of the
HVDC transaction.
216
RT_NASSET_EN
*RT_NASSET_EN_HR
=∑
=∑
CN
$-550
H
(
*RT_NASSET_VOL
x
(
-25
x
*RT_LMP_EN
$22.00
)
)
Credit
217
RT_NASSET_EN
*RT_NASSET_EN
=∑
(
*RT_NASSET_EN_HR
)
=∑
(
$-550
)
H
$-550
H
Results in a $-550.00 credit for HE 1 for Export Schedule
218
RT_NASSET_EN
Wheel Through Schedule
• HE1 100 MW was scheduled and no adjustments.
• LMP is $12 at the external CPNode where energy is being
imported into MISO.
• LMP is $17 at the external CPNode where energy is being
exported out of MISO.
• What is the charge/credit for RT_NASSET_EN?
RT_NASSET_EN
HE
RT_PHYS_
DA_PHYS_
RT_FIN_ RT_GFACO_
DA_GFACO_
VOLNet
VOLNet
VOLNet
VOLNet
VOLNet
*RT_LMP_EN
Import
1
-100
-100
0
0
0
$12
Export
1
100
100
0
0
0
$17
219
RT_NASSET_EN
Intermediate Calculations - Wheel Through Schedule
Determinant
Formula
= RT_PHYS_VOLNet - DA_PHYS_VOLNet + RT_FIN__VOLNet + RT_GFACO_VOLNet –
RT_NASSET_VOL
DA_GFACO_VOLNet
0
*RT_LMP_EN
=( -100) – (-100) + 0 + 0 + 0
Hourly Real-Time LMP ($/MWh)
12
*RT_PHYSHVDC
Hourly Real-Time PBT Volume where the AO is wheeling energy across a HVDC
transmission line.
*DA_PHYSHVDC
Hourly Day-Ahead PBT Volume where the AO is wheeling energy across a HVDC
transmission line.
*RT_LMP_ENHVDC_SRC
Hourly Real-Time LMP ($/MWh) at a Commercial Pricing Node which is the source of the
HVDC transaction.
*RT_LMP_ENHVDC_SNK
Hourly Real-Time LMP ($/MWh) at a Commercial Pricing Node which is the sink of the
HVDC transaction.
220
RT_NASSET_EN
*RT_NASSET_EN
=∑
(
*RT_NASSET_EN_HR
)
=∑
(
$0.00
)
H
$0.00
H
No charges or credits for Wheel Through Schedule
221
RT_NASSET_EN - Total
RT_NASSET_EN
$-1090
=
=
Import Schedule
$-540 Credit
+
+
Export Schedule
$-550 Credit
+
+
Through Schedule
0
Results in a $-1090.00 credit for HE 1
222
RT_NASSET_EN - Summary
The Real-Time Non-Asset Energy Amount is the product of
(1) the sum of
(a) Real-Time Physical Bilateral Transactions,
(b) Net Impact of Day-Ahead Physical Bilateral
Transactions,
(c) Real-Time Financial Bilateral Transactions,
(d) Net Impact of Real-Time Carved-Out GFA
transactions.
(2) the LMP
at each Commercial Pricing Node to settle Load
Purchases and Generator Sales for an Asset Owner.
Questions?
223
Real-Time Market
Administration Amount
(RT_ADMIN)
RT_ADMIN - Purpose
• Real-Time Market Administration Amount (RT_ADMIN)
• Collectively referred to as Tariff Schedule 17, the DA and
RT_ADMIN charge types are designed to recover the MISO cost of
operating the Day-Ahead and Real-Time Energy and Operating
Reserves Markets
• Calculated at each CPNode for each hour by multiplying an AO’s
Real-Time Market participation volume by the Hourly Energy and
Operating Reserve Markets Administration Rate
• An AO’s RT participation volume at a CPNode is based on the total
directional energy volume into and out of the CPNode, by the AO
Who gets the
charge?
Where does it go?
• AOs with net schedules originating or
terminating at the asset CPNode in the
Real-Time Market
• To the MISO to recover the cost of
operating the Real-Time Energy and
Operating Reserve Market
225
RT_ADMIN - Hierarchy
226
RT_ADMIN - Formula
*RT_ADMIN
= ∑∑
( (
AO
H
*RT_ADMIN_VOL
=∑
Determinant
*RT_ADMIN_VOL
x
*DART_ADMIN_RATE
(
CN
RT_NET_SELL_ADMIN + RT_NET_SELL_ADMIN_INT +
RT_NET_BUY_ADMIN + RT_NET_BUY_ADMIN_INT +
RT_PSEUDO_VOL
))
)
Formula
RT_NET_SELL_ADMIN
An AO's Net Hourly Admin Volume from Injection/Withdrawal, selling
FBTs, and Carve-Out GFA Transactions at Non-Interface CPNodes
(MWh)
RT_NET_SELL_ADMIN_INT
An AO's Net Hourly Admin Volume from Injection/Withdrawal, selling
FBTs, PBTs, and GFACO Transactions at Interface CPNodes (MWh)
RT_NET_BUY_ADMIN
An AO's Net Hourly Admin Volume from Injection/Withdrawal, buying
FBTs, and Carve-Out GFA Transactions at Non-Interface CPNodes
(MWh)
RT_NET_BUY_ADMIN_INT
An AO's Net Hourly Admin Volume from Injection/Withdrawal, buying
FBTs, PBTs, and GFACO Transactions at Interface CPNodes (MWh)
RT_PSEUDO_VOL
Hourly Pseudo Real-Time FBT Volume (MWh)
227
RT_ADMIN - Formula
*RT_ADMIN_VOL
Determinant
=∑
(
CN
RT_NET_SELL_ADMIN + RT_NET_SELL_ADMIN_INT +
RT_NET_BUY_ADMIN + RT_NET_BUY_ADMIN_INT +
RT_PSEUDO_VOL
)
Formula
RT_NET_SELL_ADMIN
= MAX {ABS [MIN ( 0 , RT_ASSET_IMB ) ] ,
[ Σ (RT_FINSeller) + NET_RT_GFACO_SELL ] }
RT_NET_SELL_ADMIN_INT
= MAX [ Σ ( RT_FINSeller ) , NET_RT_PHYS_SELL ] ,
+ NET_RT_GFACO_SELL
RT_NET_BUY_ADMIN
= MAX { MAX ( 0 , RT_ASSET_IMB ),
[ Σ (RT_FINBuyer) + NET_RT_GFACO_BUY ] }
RT_NET_BUY_ADMIN_INT
= MAX [ Σ ( RT_FINBuyer ) , NET_RT_PHYS_BUY ] ,
+ NET_RT_GFACO_BUY
RT_PSEUDO_VOL
= Σ ( RT_FINPseudo-Buyer ) + Σ ( RT_FINPseudo-Seller )
228
RT_ADMIN – Schedule 17 Rate
• The Schedule 17 Rate is updated on or near the first of each
month.
• Rate updates can be found on the MISO Website > Market and
Operations > Notifications > View Market Settlement Updates >
Then Month and Year for the Rates.
229
RT_ADMIN Example
Scenario
• Import Schedule – HE1 Cleared 80 MW in Day-Ahead Market
increased back to 100 MW in Real-Time Market.
• Export Schedule – HE1 cleared125 MW in Day-Ahead Market
then curtailed to 100 MW in Real-Time Market.
• Wheel Through Schedule - HE1 100 MW was scheduled and no
adjustments.
• What is the charge/credit for RT_ADMIN?
RT_ADMIN
HE
1
NET_RT_PHYS_
NET_RT_PHYS_
*DART_ADMIN_
SELL
BUY
RATE
45
0
$.098
230
RT_ADMIN Example
Intermediate Calculations
Determinant
Formula
RT_NET_SELL_ADMIN
= MAX {ABS [MIN ( 0 , RT_ASSET_IMB ) ] ,
[ Σ (RT_FINSeller) + NET_RT_GFACO_SELL ] }
RT_NET_SELL_ADMIN_INT
= MAX [ Σ ( RT_FINSeller ) , NET_RT_PHYS_SELL ] ,
+ NET_RT_GFACO_SELL
45
= MAX { MAX ( 0 , RT_ASSET_IMB ),
[ Σ (RT_FINBuyer) + NET_RT_GFACO_BUY ] }
RT_NET_BUY_ADMIN
= MAX [ Σ ( RT_FINBuyer ) , NET_RT_PHYS_BUY ] ,
+ NET_RT_GFACO_BUY
RT_NET_BUY_ADMIN_INT
0
RT_PSEUDO_VOL
=MAX[0,45], + 0
=MAX[0,0], + 0
= Σ ( RT_FINPseudo-Buyer ) + Σ ( RT_FINPseudo-Seller )
231
RT_ADMIN –Example
Charge Type Calculation
*RT_ADMIN_VOL
45 MW
*RT_ADMIN
$4.41
=∑
(
= ∑ ( 0 + 45 + 0 + 0 + 0
CN
RT_NET_SELL_ADMIN + RT_NET_SELL_ADMIN_INT +
RT_NET_BUY_ADMIN + RT_NET_BUY_ADMIN_INT +
RT_PSEUDO_VOL
CN
=
∑(
*RT_ADMIN_VOL
=
∑(
45 MW
H
H
x
x
)
)
*DART_ADMIN_RATE
$.098
)
)
Results in a $4.41charge for HE 1
232
RT_ADMIN – Summary
• The Real-Time Market Administration Amount is calculated by
multiplying an AO’s RT participation volume by the Market
Administration Rate.
• This charge type is designed to recover the MISO cost of operating
the Day-Ahead and Real-Time Energy and Operating Reserves
Markets under Tariff Schedule 17.
• In accordance with the Tariff, all assets meeting the administrative
charge exemption are not subject to the Real-Time Market
Administrative Amount charge type.
• All transactions and schedules that are not exempt, originating at, or
terminating at a CPNode are subject to this charge type.
Questions?
233
Real-Time Miscellaneous Amount
(RT_MISC)
RT_MISC - Purpose
• Real-Time Miscellaneous Amount (RT_MISC)
• A mechanism that allows the MISO to issue charges and/or credits
based on specific requirements to either one AO or to the entire
market
• Facilitates the following charges and/or credits:
– Method A: Charge or credit applied to a single AO
– Method B: Charge or credit applied to a single AO with the opposite
charge or credit spread to all other AOs based on the
OD’s: 1) LRS, 2) MRS, or 3) FRS
– Method C: Charge or credit applied to all AOs based on an OD’s:
1) LRS, 2) MRS, or 3) FRS
Who gets the
charge/credit?
Where does it go?
• Individual AOs or all AOs participating
in the Real-Time Market
• Individual AOs or all AOs participating
in the Real-Time Market
235
RT_MISC - Hierarchy
236
RT_MISC - Formula
*RT_MISC
=∑
(
METHOD_A
+
METHOD_B
+
METHOD_C
)
The charge or credit applied to a single AO ($)
METHOD_A
METHOD_B
METHOD_C
=
This charge only applies to the AO that matches the single Designated AO that is
identified to receive the full charge or credit.
=
The daily charge or credit applied by AO based on LRS,
MRS, or FRS for an Operating Day ($)
=
The daily charge or credit applied by AO based on LRS,
MRS, or FRS for an Operating Day ($)
237
RT_MISC - Formula
• The following must be known in order to apply a single
miscellaneous transaction:
– 1) Determine the total transaction miscellaneous charge or credit amount.
– 2) Determine whether the full amount is for a single AO (Method A or B) or is
to be allocated to the entire market (Method C).
– 3) If in step 2 the full amount is for a single AO, determine whether all other
AOs are responsible for paying for or collecting the amount that is given to
the single AO (Method B if they are, Method A if they are not).
– 4) If Method C was chosen in step 2 or if Method B was chosen in step 3,
determine which distribution ratio share allocation method must be used.
Load Ratio Share (LRS)
LRS is equal to an AO’s total hourly Load divided by the total hourly Load for all
the MISO.
Market Ratio Share (MRS)
MRS is equal to an AO’s total hourly DA and RT Administration Volume divided
by the total hourly DA and RT Administration Volume for all the MISO.
FTR Ratio Share (FRS)
FRS is equal to an AO’s total hourly FTR Profile Volume divided by the total
hourly AO FTR Profile Volume for all the MISO.
238
RT_MISC – Example
Scenario
•
Assume DA_ADMIN_VOL was suppose to be 450 MW
•
Assume RT_ADMIN_VOL was suppose to be 50 MW.
•
Market Ratio Share (MRS) is .10 which is the sum of the DA_ADMIN_VOL and
the RT_ADMIN_VOL divided by the Day-Ahead/Real-Time Admin_Vol for all of
MISO.
•
DA_ADMIN changed from $39.69 to $44.10.
•
RT_ADMIN changed from $4.41 to $4.90.
•
Day-Ahead and Real-Time Administration Volumes for all of MISO is 5000 MW.
•
What is the charge/credit for RT_MISC?
RT_MISC
HE
1
DA_ADMIN_
RT_ADMIN_
DA/RT ADMIN VOL
VOL
VOL
MISO
450
50
5000
MRS
AO Charge
.10
$4.90
239
RT_MISC – Example
Charge Type Calculation
*RT_MISC
=∑
$4.90
=∑
(
(
METHOD_A
$0
+
METHOD_B
+
$4.90
+
METHOD_C
)
+
$0
)
Results in a $4.90 charge to the AO for HE 1
$.49
(
=∑
$0
+
($4.90 x .10)
+
$0
)
Results in a $.49 charge for this AO and a charge of $.10 per
MW to all other AOs in the market for HE 1
240
RT_MISC – Summary
• The Real-Time Miscellaneous Amount allows the MISO to issue
charges and/or credits based on specific requirements to either one
AO or to the entire market.
• Can be used for charges or credits ordered by the IMM.
• The MISO follows a strict internal approved procedure process prior
to initiating this charge.
• The Real-Time Settlement Statement specifically lists each
miscellaneous charge along with:
•
•
•
•
•
A reference identifier
The reason for the charge
Whether the charge or credit is for a single AO or the entire market
The ratio share being applied if applicable
The amount of the charge or credit
Questions?
241
Real-Time Schedule 24
Allocation Amount
(RT_SCHD_24_ALC)
RT_SCHD_24_ALC - Purpose
• Real-Time Schedule 24 Allocation Amount (RT_SCHD_24_ALC)
•
•
•
Cost mechanism by which LBAs recover the cost of labor and material
associated with market operations
Calculated by multiplying the RT Administrative volume by the Schedule 24
Rate to obtain an hourly dollar amount
An AO’s RT participation volume at a CPNode is based on the total
directional energy volume, into and out of the CPNode, by the AO
Who gets the
charge?
Where does it go?
• Asset Owners participating in the
Real-Time Energy and Operating
Reserve Market
• Used to fund Schedule 24 distribution
back to the LBAs
243
RT_SCHD_24_ALC - Hierarchy
244
RT_SCHD_24_ALC - Formula
*RT_SCHD_24_ALC
=∑
H
(
*RT_ADMIN_VOL
x
*SCHD_24_ALC_RATE
)
Real-Time Administration Volume (MWh)
*RT_ADMIN_VOL
=
See *RT_ADMIN Charge Type
Hourly Schedule 24 Allocation Rate ($/MWh)
*SCHD_24_ALC_RATE
=
in
• LBAs submit the previous year’s applicable costs to the MISO by May 1st
st
st
order to calculate the rate(s) for the upcoming Schedule year (June 1 - May 31 ).
• The allocation rate is set for each calendar month.
245
RT_SCHD – Schedule 24 Rate
• The Schedule 24 Rate is updated on or near the first of each
month.
• Rate updates can be found on the MISO Website > Market and
Operations > Notifications > View Market Settlement Updates >
Then the Month and Year for the rates.
246
RT_SCHD_24_ALC Example
Scenario
• Using the information from the RT_ADMIN example the
RT_ADMIN_VOL is 45 MW.
• What is the charge/credit for RT_SCHD_24_ALC?
RT_SCHD_24_ALC
HE
*RT_ADMIN_VOL
*SCHD_24_ALC_RATE
1
45
$.011
247
RT_SCHD_24_ALC – Example
Charge Type Calculation
*RT_SCHD_24_ALC
=∑
*RT_ADMIN_VOL
x
*SCHD_24_ALC_RATE
=∑
45 MW
x
$.011
H
$.50
H
(
(
)
)
Results in a $.50 charge for HE 1
248
RT_SCHD_24_ALC – Summary
• The RT Schedule 24 Allocation Amount constitutes the
collected monies, on the Real-Time Market, used to fund
Schedule 24 distribution back to the LBAs and is calculated by
multiplying the RT Administrative volume by the Schedule 24
Rate.
• The aggregation of Day-Ahead and Real-Time Allocation
amounts is equal to the full daily distribution of Schedule
24 funds back to the LBAs.
Questions?
249
Real-Time Net Inadvertent Distribution
(RT_NI_DIST)
RT_NI_DIST - Purpose
• Real-Time Net Inadvertent Distribution (RT_NI_DIST)
•
•
•
•
Represents daily allocation to AOs of any energy dollars that result from the
MISO BA Net Inadvertent for an Operating Day
On an hourly basis each LBA is tasked with balancing their energy generation
supply, load, and Net Scheduled Interchange (NSI)
The difference between the NAI and the NSI is Net Inadvertent
Calculated by averaging the LMP from all generators in the LBA times the
volume of the Inadvertent and summing to a daily total. This amount is
allocated based on market participation using the Net Inadvertent Distribution
Factor for each AO
Who gets the
charge?
Where does it come
from?
• AOs participating in the DA and RT
Energy Markets (by LBA)
• Uses energy dollars that result from
the MISO BA Net Inadvertent for an OD
251
RT_NI_DIST - Hierarchy
252
RT_NI_DIST - Formula
*RT_NI_DIST
=
*MISO_NI
x
*NI_DIST_FCT
MISO Daily Total Net Inadvertent Cost ($)
*MISO_NI
=
ΣH ( ΣMISO ( ( NAI - NSI ) x RT_GEN_BA_LMP) )
= AVG [ IF ( CPNode = Gen
Asset, RT_LMP_EN, 0 ) ]
Daily Net Inadvertent Distribution Factor by AO (factor)
*NI_DIST_FCT
= AO_MKT_VOL / MISO_MKT_VOL
= ΣH ( RT_ADMIN_VOL + DA_ADMIN_VOL )
253
RT_NI_DIST – Example
Scenario
• The LBA reports NAI of 400 MW and NSI of 300 MW.
• The Hourly LBA Generation Average LMP is $18.75
• Day-Ahead and Real-Time Market Administration Volumes equal
450 MW.
• The MISO reports the Total Administration Volume for the OD for
all AOs as 10,500 MW
• What is the charge/credit for RT_NI_DIST?
RT_NI_DIST
HE
NAI
NSI
RT_GEN_BA_LMP
AO_MKT_VOL
MISO_MKT_VOL
1
400
300
$18.75
450
10,500
254
RT_NI_DIST – Example
Intermediate Calculations
Determinant
Formula
= ΣH ( ΣMISO ( ( NAI - NSI ) x RT_GEN_BA_LMP) )
MISO_NI
$1,875
NI_DIST_FCT
= ΣH ( ΣMISO ( ( 400 - 300 ) x $18.75) )
= AO_MKT_VOL / MISO_MKT_VOL
.0428
= 450 / 10500
*Note that only the MISO_NI and NI_DIST_FCT values are given on the
Real-Time Settlement Statement, not the determinants that go into the
calculations. The MISO_NI amount can be found in the Market Wide
Determinants section of the Statement and the NI_DIST_FCT value can
be found in the Asset Owner Determinants section.
255
RT_NI_DIST – Example
Charge Type Calculation
*RT_NI_DIST
=
*MISO_NI
x
*NI_DIST_FCT
$80.25
=
$1,875
x
.0428
Results in a $80.25 charge for HE1
256
RT_NI_DIST – Summary
• Real-Time Net Inadvertent Distribution represents the daily allocation
to AOs of any energy dollars that result from the MISO BA Net
Inadvertent for an Operating Day.
• The hourly energy cost of the Net Inadvertent is calculated by
averaging the LMP from all generators in the LBA times the volume of
the Inadvertent (NAI – NSI) for that same Hour.
• The dollar impact for all hours in an OD for all the MISO LBAs is
summed and is allocated to AOs based on their participation in the DA
and RT Energy Markets for the OD using the Net Inadvertent
Distribution Factor.
Questions?
257
Real-Time Revenue
Neutrality Uplift Amount
(RT_RNU)
RT_RNU - Purpose
• Real-Time Revenue Neutrality Uplift Amount (RT_RNU)
• Charge type set up as a revenue distribution balancing mechanism for
charges and credits attributable to load or that have no other distribution
method to AOs
• On an hourly basis, all charges and credits are summed, and the
subsequent total charge or credit for the Hour is distributed to AOs
based on their LRS
• Calculated by multiplying the MISO Hourly Revenue Neutrality
Adjustment Credit or Charge Amount times the AO to MISO LRS factor
Who gets the
charge?
• Real-Time MISO Load based on LRS
Where does it go?
• Various depending on ‘component’
259
RT_RNU – Components
• The RT_RNU Charge Type is made up of seven components. The total
dollar amount for all of the MISO is given on each AO’s Settlement
Statement for each hour. The following charges and/or credits are
distributed through this charge type:
–
Revenue Inadequacy Uplift (RI_UPLIFT)
Revenue Inadequacy ensures on an hourly basis that the MISO is not revenue short
or long for each Hour. Specifically, Revenue Inadequacy verifies that revenue
related to energy and losses remain balanced. DA and RT hourly revenue shortfalls
and excesses are dispersed through this charge type.
–
Joint Operating Agreement Uplift (JOA_MISO_UPLIFT)
JOAs are arrangements with the MISO and bordering ISOs that enable one ISO on
an hourly basis to request the other to re-dispatch, to relieve, or make available,
additional transmission flowgate capacity for use by the requesting ISO.
For the MISO, any funds received for DA or RT Market coordination will be added to
the DA or RT Congestion Funds and any funds paid will reduce the Congestion
Funds. If during an Hour there are not sufficient funds to pay for requested additional
flowgate capacity, the additional funds are collected as an uplift in this charge type.
260
RT_RNU – Components
–
GFAOB FBT Congestion Rebate Distribution Amount Uplift
(MISO_RT_GFAOB_DIST)
DA GFAOB Transactions are charged the Marginal Cost of Congestion of the LMP
per the DA FBT Congestion Amount charge type. The congestion charge rebate is
primarily funded through MISO held FTRs revenues representing the Option B
transaction volume. Any funding shortfall is collected from AOs in this uplift.
–
Carved-Out GFA Congestion Rebate Distribution Amount Uplift
(MISO_RT_GFACO_DIST)
DA and RT GFACO Transactions are charged the Marginal Cost of Congestion of
the LMP per the DA and RT FBT Congestion Amount charge types. The congestion
charge rebates are primarily funded through MISO held FTRs revenues representing
the Carved-Out GFA volume. Any funding shortfall is collected from AOs in this
uplift.
261
RT_RNU – Components
–
Real-Time RSG MWPs Second Pass Distribution Uplift Amount
(MISO_RT_RSG_DIST2)
This is the secondary funding mechanism for the RT RSG MWP Amount credited to
AOs. This uplift is only used when the total RT RAC Generation Resource committed
volume for the Hour exceeds the AO’s total RT RSG First Pass Distribution Volume.
–
Real-Time Contingency Reserve Deployment Failure Charge Uplift Amount
(MISO_CRDFC_UPLIFT)
This amount represents the offsetting credits to the Revenue Neutrality Uplift Charge
Type funded by the charges (RT_ASM_CRDFC) incurred by Resources that fail to
deploy Contingency Reserves at or above the Contingency Reserve Deployment
Instruction.
–
Real-Time Price Volatility Make-Whole Payment Uplift
(MISO_PV_MWP_UPLIFT)
This amount represents the charges to the Revenue Neutrality Uplift Charge Type
used to fund the credits received by Resources through the RT_PV_MWP Charge
Type.
262
RT_RNU - Hierarchy
263
RT_RNU - Formula
*RT_RNU
=∑
(
H
*MISO_LRS_FCTAO
x
MISO_RT_RNU
)
AO to MISO Load Ratio Share Factor (factor)
*MISO_LRS_FCTAO
=
AO_LRS_VOL / ΣMISO ( AO_LRS_VOL )
• The Hourly AO Total LRS Volume represents the total load volume including
physical exports out of the MISO for an AO.
•Physical exports do not include pseudo-tie schedules or Carved-Out
Grandfather Agreement Transactions.
MISO Hourly Revenue Neutrality Adjustment
Credit or Charge Amount ($)
MISO_RT_RNU
=
*RI_UPLIFT + *JOA_MISO_UPLIFT + *MISO_RT_RSG_DIST2 +
*MISO_RT_GFAOB_DIST + *MISO_RT_GFACO_DIST +
*MISO_CRDFC_UPLIFT + *MISO_PV_MWP_UPLIFT
264
RT_RNU - Formula
=
MISO_RT_RNU
*RI_UPLIFT + *JOA_MISO_UPLIFT + *MISO_RT_RSG_DIST2 +
*MISO_RT_GFAOB_DIST + *MISO_RT_GFACO_DIST +
*MISO_CRDFC_UPLIFT + *MISO_PV_MWP_UPLIFT
Total MISO Hourly Revenue Inadequacy Uplift ($)
*RI_UPLIFT
=
[ (MISO_DA_RI + MISO_RT_RI + MISO_RT_HR_CG_FND) x (-1) ]
MISO_LOSS_DIST_UPLIFT
+
Total MISO Hourly Revenue JOA Uplift ($)
*JOA_MISO_UPLIFT
=
MISO_DA_JOA_UPLIFT + MISO_RT_JOA_UPLIFT
= MAX [ 0 , (MISO_DA_JOA_AP - MISO_DA_HR_CG_FOR_JOA) ]
*MISO_RT_GFAOB_DIST
=
Hourly Real-Time GFAOB Congestion Rebate Distribution
Amount ($)
MAX { 0 , [ (-1) x MISO_GFAOB_RBT_CG ] [ (-1) x FTR_HR_ALC_FCT x MISO_OB_FTR_TARG_CR ] }
Hourly Total GFACO Congestion Rebate Distribution Amount ($)
*MISO_RT_GFACO_DIST
=
MAX { 0 , [ (-1) x (MISO_DA_GFACO_RBT_CG + MISO_RT_GFACO_RBT_CG)]
- [ (-1) x FTR_HR_ALC_FCT x MISO_CO_FTR_TARG_CR ] }
265
RT_RNU - Formula
MISO_RT_RNU
=
*RI_UPLIFT + *JOA_MISO_UPLIFT + *MISO_RT_RSG_DIST2 +
*MISO_RT_GFAOB_DIST + *MISO_RT_GFACO_DIST +
*MISO_CRDFC_UPLIFT + *MISO_PV_MWP_UPLIFT
Hourly MISO RT RSG Second Pass Distribution Uplift Amount ($)
*MISO_RT_RSG_DIST2
=
(MISO_RT_RSG_MWP + MISO_RT_RSG_DIST1) x (-1)
*Only calculated when total MWPs exceed the amount which can be distributed
via the first pass charge type (RT_RSG_DIST1).
Hourly RT Contingency Response Deployment Failure Uplift Amount ($)
*MISO_CRDFC_UPLIFT
=
Represents the offsetting credit for the total funds collected through the
RT_ASM_CRDFC Charge Type from all AOs.
Hourly Real-Time Price Volatility Make-Whole Payment Uplift Amount ($)
*MISO_PV_MWP_UPLIFT
=
Represents the charges used to fund the credits received by Resources through the
RT_PV_MWP Charge Type from all AOs.
266
RT_RNU – Example
Scenario
• Export Schedule – HE1 cleared125 MW in Day-Ahead Market
then curtailed to 100 MW in Real-Time Market.
• MISO total Load Volume (net of GFA Transaction Volume) is
6,500 MW
• The MISO submitted credit or charge amounts for each
component of MISO_RT_RNU. The total amount to be allocated to
AOs is $1,200 for HE 1
• What is the charge/credit for RT_RNU?
RT_RNU
HE
AO_LRS _VOL
AO_LRS_VOL
MISO_RT_RNU
MISO
1
100
6,500
$1,200
267
RT_RNU – Example
Intermediate Calculations
*MISO_LRS_FCTAO
=
AO_LRS_VOL / ΣMISO ( AO_LRS_VOL )
.0153
=
100 / 6,500
268
RT_RNU – Example
Charge Type Calculation
*RT_RNU
=∑
*MISO_LRS_FCTAO
x
MISO_RT_RNU
=∑
.0153
x
$1,200
(
H
$18.36
(
H
)
)
Results in a $18.36 charge for HE1.
269
RT_RNU – Summary
• The Real-Time Revenue Neutrality Uplift Amount is a charge type
set up as a revenue distribution balancing mechanism for charges
and credits that have no other distribution method to AOs.
• On an hourly basis, all charges and credits that have no other
distribution method are summed, and the subsequent total charge
or credit for the Hour is distributed to AOs by multiplying this
amount times the AO to MISO LRS factor.
Questions?
270
Real-Time Spinning Reserve
Cost Distribution Amount
(RT_ASM_SPIN_DIST)
RT_ASM_SPIN_DIST - Purpose
• Spinning Reserve Cost Distribution Amount (RT_ASM_SPIN_DIST)
•
•
Represents the allocation of the total cost of procurement of Spinning
Reserve in the Day-Ahead and Real-Time Energy and Operating Reserve
Market by the AO percent share of Load in a Reserve Zone
Calculated hourly by taking the sum of:
–
–
The Hourly Spinning Reserve Distribution Volume for an AO in a Reserve Zone
multiplied by the Hourly Spinning Reserve Distribution Rate, and
The Hourly Spinning Reserve GFA Distribution Volume for an AO in a Reserve
Zone multiplied by the Hourly Spinning Reserve GFA Distribution Rate
Who gets the
charge?
Where does it go?
• Payments are funded by AOs in a
Reserve Zone through the
RT_ASM_SPIN Charge Type
• Asset Owners that own Resources with
cleared Spinning Reserve
272
RT_ASM_SPIN_DIST – Hierarchy
*In order to conserve space, determinants for the ASM_SPIN_DIST_RATEZN and
ASM_SPIN_GFA_DIST_RATEZN calculations are not shown. These rates are given on an AO’s
Real-Time statement and the calculations will be discussed later.
273
RT_ASM_SPIN_DIST - Formula
*RT_ASM_SPIN_DIST
∑∑
=
( [(
+(
H
*ASM_SPIN_DIST_VOLAO-ZN
AO-ZN
*RT_ASM_SPIN_GFA_
SELLER_DIST_VOLAO-ZN
x
*ASM_SPIN_DIST_RATEZN
x
*ASM_SPIN_GFA_
DIST_RATEZN
)
)
274
RT_ASM_SPIN_DIST - Formula
Hourly Spinning Reserve Distribution Volume (MWh)
*ASM_SPIN_DIST_VOLAO-ZN
=
ΣCN ( ASM_SPIN_DIST_VOLCN x PCT_CPN_IN_ZN )
= IF ASM_SPIN_DIST_EXEMPT = ‘N’ THEN [ MAX (RT_BLL_MTRCN, 0 ) { ΣTransactions (RT_GFACOBuyer x PRE_888_SPIN ) } + { ΣTransactions
RT_PHYSBuyer } ] ELSE 0
Hourly Spinning Reserve Distribution Rate ($/MWh)
*ASM_SPIN_DIST_RATEZN
=
ΣCN [ { ( ( DA_SPIN_VOLCN x DA_SPIN_MCPCN ) + ( RTN_SPIN_VOLCN x
RT_SPIN_MCPCN ) - ( RT_ASM_SPIN_GFA_SELLER_DIST_VOLCN x
ASM_SPIN_GFA_DIST_RATEZN ) ) x PCT_CPN_IN_ZN } /
( ASM_SPIN_DIST_VOLCN x PCT_CPN_IN_ZN ) ]
Hourly Spinning Reserve GFA Distribution Volume (MWh)
*RT_ASM_SPIN_GFA_
SELLER_DIST_VOLAO-ZN
=
ΣCN ( RT_ASM_SPIN_GFA_SELLER_DIST_VOLCN x PCT_CPN_IN_ZN )
= IF ASM_SPIN_DIST_EXEMPT = ‘N’ THEN { ΣTransactions (RT_GFACOSeller
x PRE_888_SPIN ) } ELSE 0
Hourly Spinning Reserve GFA Distribution Rate ($/MWh)
*ASM_SPIN_GFA_
DIST_RATEZN
=
ΣCN [ { ( ( DA_SPIN_VOLCN x DA_SPIN_MCPCN ) +
( RTN_SPIN_VOLCN x RT_SPIN_MCPCN ) ) x PCT_CPN_IN_ZN } /
( ( RT_ASM_SPIN_GFA_SELLER_DIST_VOLCN +
ASM_SPIN_DIST_VOLCN ) x PCT_CPN_IN_ZN ) ]
275
RT_ASM_SPIN_DIST –Example
Scenario
• Export Schedule – HE1 cleared125 MW in Day-Ahead Market
then curtailed to 100 MW in Real-Time Market.
• Applicable rates have been provided by the MISO.
• What is the charge/credit for RT_ASM_SPIN_DIST?
RT_ASM_SPIN_DIST
HE
RT_PHYSBuyer
*PCT_CPN_IN_ZN
*ASM_SPIN_DIST_RATEZN
1
100
100%
0.02
276
RT_ASM_SPIN_DIST – Example
Intermediate Calculations
Determinant
Formula
= IF ASM_SPIN_DIST_EXEMPT = ‘N’ THEN [ MAX (RT_BLL_MTRCN, 0 ) { ΣTransactions (RT_GFACOBuyer x PRE_888_SPIN ) } + { ΣTransactions RT_PHYSBuyer } ] ELSE 0
ASM_SPIN_DIST_VOLCN
100
RT_ASM_SPIN_GFA_SELLER_
DIST_VOLCN
= IF ASM_SPIN_DIST_EXEMPT = ‘N’ THEN [ MAX ( 0, 0 ) { ΣTransactions ( 0 x 0 ) } + {ΣTransactions 100 } ] ELSE 0
= IF ASM_SPIN_DIST_EXEMPT = ‘N’ THEN { ΣTransactions (RT_GFACOSeller x
PRE_888_SPIN ) } ELSE 0
= IF ASM_SPIN_DIST_EXEMPT = ‘N’ THEN { ΣTransactions ( 0 x 0 ) } ELSE 0
Determinant
Formula
*ASM_SPIN_DIST_VOLAO-ZN
100
*RT_ASM_SPIN_GFA_
SELLER_DIST_VOLAO-ZN
= ΣCN ( ASM_SPIN_DIST_VOLCN x PCT_CPN_IN_ZN )
= ΣCN ( 100 x 1)
= ΣCN ( RT_ASM_SPIN_GFA_SELLER_DIST_VOLCN x PCT_CPN_IN_ZN )
= ΣCN ( 0 x .06 )
277
RT_ASM_SPIN_DIST – Example
Charge Type Calculation
=∑ ∑
( [(
+(
H
$2.00
∑∑
AO-ZN
*RT_ASM_SPIN_GFA_
SELLER_DIST_VOLAO-ZN
x
*ASM_SPIN_DIST_RATEZN
x
*ASM_SPIN_GFA_
DIST_RATEZN
)
)
=
( [(
+(
H
*ASM_SPIN_DIST_VOLAO-ZN
AO-ZN
100 MW
x
0.02
0 MW
x
$0
Results in a $2.00 charge for HE 1
)
)
278
RT_ASM_SPIN_DIST – Summary
• The Spinning Reserve Cost Distribution Amount represents
the allocation of the total cost of procurement of Spinning
Reserve in the Day-Ahead and Real-Time Energy and
Operating Reserve Market by the AO percent share of
Load in a Reserve Zone.
• Calculated hourly by taking the sum of:
•
•
The Hourly Spinning Reserve Distribution Volume for an AO in a
Reserve Zone multiplied by the Hourly Spinning Reserve
Distribution Rate, and
The Hourly Spinning Reserve GFA Distribution Volume for an AO in
a Reserve Zone multiplied by the Hourly Spinning Reserve GFA
Distribution Rate
Questions?
279
Real-Time Supplemental Reserve
Cost Distribution Amount
(RT_ASM_SUPP_DIST)
RT_ASM_SUPP_DIST - Purpose
•
Supplemental Reserve Cost Distribution Amount (RT_ASM_SUPP_DIST)
•
•
Represents the allocation of the total cost of procurement of Supplemental
Reserve in the Day-Ahead and Real-Time Energy and Operating Reserve
Market by the AO percent share of Load in a Reserve Zone
Calculated hourly by taking the sum of:
–
–
The Hourly Supplemental Reserve Distribution Volume for an AO in a Reserve
Zone multiplied by the Hourly Supplemental Reserve Distribution Rate, and
The Hourly Supplemental Reserve GFA Distribution Volume for an AO in a
Reserve Zone multiplied by the Hourly Supplemental Reserve GFA
Distribution Rate
Who gets the
charge?
Where does it go?
• Payments are funded by AOs in a
Reserve Zone through the
RT_ASM_SUPP Charge Type
• Asset Owners that own Resources with
cleared Supplemental Reserve
281
RT_ASM_SUPP_DIST – Hierarchy
*In order to conserve space, determinants for the ASM_SUPP_DIST_RATEZN and
ASM_SUPP_GFA_DIST_RATEZN calculations are not shown. These rates are given on an
AO’s Real-Time statement and the calculations will be discussed later.
282
RT_ASM_SUPP_DIST - Formula
*RT_ASM_SUPP_DIST
∑∑
=
( [(
+(
H
*ASM_SUPP_DIST_VOLAO-ZN
AO-ZN
*RT_ASM_SUPP_GFA_
SELLER_DIST_VOLAO-ZN
x
*ASM_SUPP_DIST_RATEZN
x
*ASM_SUPP_GFA_
DIST_RATEZN
)
)
283
RT_ASM_SUPP_DIST - Formula
Hourly Supplemental Reserve Distribution Volume (MWh)
*ASM_SUPP_DIST_VOLAO-ZN
*ASM_SUPP_DIST_RATEZN
=
ΣCN ( ASM_SUPP_DIST_VOLCN x PCT_CPN_IN_ZN )
= IF ASM_SUPP_DIST_EXEMPT = ‘N’ THEN [ MAX (RT_BLL_MTRCN, 0 ) { ΣTransactions (RT_GFACOBuyer x PRE_888_SUPP ) } + { ΣTransactions
RT_PHYSBuyer } ] ELSE 0
Hourly Supplemental Reserve Distribution Rate
ΣCN($/MWh)
[ { ( ( DA_SUPP_VOLCN x DA_SUPP_MCPCN ) + ( RTN_SUPP_VOLCN x
=
RT_SUPP_MCPCN ) - ( RT_ASM_SUPP_GFA_SELLER_DIST_VOLCN x
ASM_SUPP_GFA_DIST_RATEZN ) ) x PCT_CPN_IN_ZN } /
(ASM_SUPP_DIST_VOLCN x PCT_CPN_IN_ZN ) ]
Hourly Supplemental Reserve GFA Distribution Volume (MWh)
*RT_ASM_SUPP_GFA_
SELLER_DIST_VOLAO-ZN
=
ΣCN ( RT_ASM_SUPP_GFA_SELLER_DIST_VOLCN x PCT_CPN_IN_ZN )
= IF ASM_SUPP_DIST_EXEMPT = ‘N’ THEN { ΣTransactions
(RT_GFACOSeller x PRE_888_SUPP ) } ELSE 0
Hourly Supplemental Reserve GFA Distribution Rate ($/MWh)
*ASM_SUPP_GFA_
DIST_RATEZN
=
ΣCN [ { ( ( DA_SUPP_VOLCN x DA_SUPP_MCPCN ) +
( RTN_SUPP_VOLCN x RT_SUPP_MCPCN ) ) x PCT_CPN_IN_ZN } /
( ( RT_ASM_SUPP_GFA_SELLER_DIST_VOLCN +
ASM_SUPP_DIST_VOLCN ) x PCT_CPN_IN_ZN ) ]
284
RT_ASM_SUPP_DIST – Example
Scenario
• Export Schedule – HE1 cleared125 MW in Day-Ahead Market
then curtailed to 100 MW in Real-Time Market.
• Applicable rates have been provided by the MISO
• What is the charge/credit for RT_ASM_SUPP_DIST?
RT_ASM_SUPP_DIST
HE
*RT_PHYS
*PCT_CPN_IN_ZN
*ASM_SUPP_DIST_RATEZN
100%
0.01
Buyer
1
100
285
RT_ASM_SUPP_DIST – Example
Intermediate Calculations
Determinant
Formula
= IF ASM_SUPP_DIST_EXEMPT = ‘N’ THEN [ MAX (RT_BLL_MTRCN, 0 ) { ΣTransactions (RT_GFACOBuyer x PRE_888_SUPP ) } + { ΣTransactions RT_PHYSBuyer } ] ELSE 0
ASM_SUPP_DIST_VOLCN
100
= IF ASM_SUPP_DIST_EXEMPT = ‘N’ THEN [ MAX ( 0, 0 ) { ΣTransactions ( 0 x 0 ) } + {ΣTransactions 100 } ] ELSE 0
RT_ASM_SUPP_GFA_SELLER_ = IF ASM_SUPP_DIST_EXEMPT = ‘N’ THEN { ΣTransactions (RT_GFACOSeller x
DIST_VOLCN
PRE_888_SUPP ) } ELSE 0
= IF ASM_SUPP_DIST_EXEMPT = ‘N’ THEN { ΣTransactions ( 0 x 0 ) } ELSE 0
Determinant
Formula
*ASM_SUPP_DIST_VOLAO-ZN = ΣCN ( ASM_SUPP_DIST_VOLCN x PCT_CPN_IN_ZN )
100
*RT_ASM_SUPP_GFA_
SELLER_DIST_VOLAO-ZN
= ΣCN (100 x 1)
= ΣCN ( RT_ASM_SUPP_GFA_SELLER_DIST_VOLCN x PCT_CPN_IN_ZN )
= ΣCN ( 0 x 0)
286
RT_ASM_SUPP_DIST – Example
Charge Type Calculation
=∑ ∑
( [(
+(
H
$1.00
∑∑
AO-ZN
*RT_ASM_SUPP_GFA_
SELLER_DIST_VOLAO-ZN
x
*ASM_SUPP_DIST_RATEZN
x
*ASM_SUPP_GFA_
DIST_RATEZN
)
)
=
( [(
+(
H
*ASM_SUPP_DIST_VOLAO-ZN
AO-ZN
100 MW
x
.01
0 MW
x
0
Results in a $1.00 charge for HE 1
)
)
287
RT_ASM_SUPP_DIST – Summary
• The Supplemental Reserve Cost Distribution Amount represents the
allocation of the total cost of procurement of Supplemental Reserve
in the Day-Ahead and Real-Time Energy and Operating Reserve
Market by the AO percent share of Load in a Reserve Zone.
• Calculated hourly by taking the sum of:
•
•
The Hourly Supplemental Reserve Distribution Volume for an AO in
a Reserve Zone multiplied by the Hourly Supplemental Reserve
Distribution Rate, and
The Hourly Supplemental Reserve GFA Distribution Volume for an
AO in a Reserve Zone multiplied by the Hourly Supplemental
Reserve GFA Distribution Rate.
Questions?
288
Break
289
Real-Time Revenue Sufficiency
Guarantee First Pass Distribution
Amount (RT_RSG_DIST1)
RT_RSG_DIST1 - Purpose
• Real-Time Revenue Sufficiency Guarantee First Pass
Distribution Amount (RT_RSG_DIST1)
• This charge funds the RSG Make Whole Payments paid to the
generation Asset Owners
• Charges Asset Owner’s assets and schedules with an adverse impact on
a constraint based on the amount of deviation and the Constraint
Contribution Factor (CCF) for the Active Transmission Constraint
• Charges Asset Owner’s sum total of asset-related deviations and
demand changes which are deemed to be a cause for Real-Time RAC
generation commitments
Who gets the
charge/credit?
• Asset Owners with assets and
schedules which adversely impact
Constraints and deviations and
demand changes resulting in
commitments
Where does it go?
• Asset Owners with generation (via
Make Whole Payment)
291
RT_RSG_DIST1 – Hierarchy
•
•
Intermediate Calculations for CMC_DEV_VOL and ATC_CMC_RATE are in
Section A.1.2 of the Calculation Guide.
Intermediate Calculations for DDC_DEL_VOL and MISO_DDC_RATE are in
Section A.1.3 of the Calculation Guide.
292
RT_RSG_DIST1 - Formula
*RT_RSG_DIST1
(
=∑
H
*RT_RSG_DIST1_HR
)
Hourly Real-Time RSG Distribution Amount
*RT_RSG_DIST1_HR
=
CMC_DIST + DDC_DIST
293
RT_RSG_DIST1
CMC_DEV_VOL =
DDC_DEV_VOL =
CMC_NDL_ VOL
DDC_NDL_ VOL
NDL Dev
RT Dev
+
+
CMC_RT_VOL
DDC_ RT_VOL
294
RT_RSG_DIST1
CMC_DEV_VOL =
NDL Dev
RT Dev
CMC_NDL_ VOL
Sum of All +/- Deviation x CCF
Net Positive Total is added to RT Dev.
+
+
CMC_RT_VOL
Sum of all Positive (Deviation x CCF)
295
RT_RSG_DIST1
What is a CCF?
A Commercial Pricing Node’s Constraint Contribution Factor
(CCF) represents the impact that an incremental increase or
decrease in flow of one MW has on a given Active
Transmission Constraint. CCF varies from -1 to 1
CCF
Positive
Negative
Hurt if Increased Supply, Help if Decreased
Supply
Help if Increased Supply, Hurt if Decreased
Supply
296
RT_RSG_DIST1
DDC_DEV_VOL =
NDL Dev
Sum of All +/- Deviation
Net Positive Total is added to RT Dev
+
RT Dev
Sum of all MAX(NDL Deviation,0 ) or
ABS( RT Deviation)
DDC_NDL_ VOL
+
DDC_ RT_VOL
297
RT _RSG_DIST1
CMC1
CMC2
DDC
CMC4
CMC3
CMC_DEV_VOL is for individual constraints
DDC_DEV_VOL is for
whole MISO
298
RT_RSG_DIST1
Import Scenario
Approved Volume Scenario
Change
After to
Change Prior to NDL
NDL
Import
Import
Import/Ex Day Ahead Schedule No RT
adjustment
port
Import
Import
Import
Import
No Day Ahead Schedule/
RT =100
No Day Ahead Schedule,
RT create before NDL, no
RT Adj
No Day Ahead Schedule,
RT create before NDL, RT
Adj to 0
RT Create After NDL, No
adj.
100
100
100
0
Negative
CCF =
-1
Help if Increased Supply, Hurt if Decreased Supply
NDL
Change/ OATI
CMC
RT. DEV. DEV
Created&A RT NDL
pproved Vol. DEV. Vol. Vol.
Vol.
Day
Change/
11:00 AM Ahead Created&
Day Prior Clearing Approved NDL
Day Ahead Schedule
Curtail/adjusted before
NDL to zero
Day Ahead Schedule
Curtail/adjusted After NDL
to zero
Assume
RT CMC
DEV
CMC
Vol.
Vol
NDL
DEV
Vol.
RT DEV DDC
Vol.
Vol.
0
0
-100
0
100
0
100
100
0
100
100
100
0
0
-100
0
100
100
0
100
100
100
100
100
100
0
0
0
0
0
0
0
0
0
0
0
100
0
100
0
0
0
0
100
100
0
0
100
100
100
100
0
-100
0
0
-100
0
0
0
0
100
100
0 0
100
-100
-100
100
100
-100
100
100
0
0
0
0
100 0
0
0
0
0
0
0
0
0
299
RSG_RSG_DIST1
Export Scenario
Approved Volume Scenario
Change
After
Change Prior to NDL
to NDL
Change
/
Create
Day Ahead d&App
Clearing
roved NDL
11:00 AM
Day Prior
Export
Export
Export
Export
Export
Day Ahead Schedule
Curtail/adjusted before NDL
to zero
Day Ahead Schedule
Curtail/adjusted After NDL
to zero
No Day Ahead Schedule/ RT
=100
No Day Ahead Schedule, RT
create before NDL, no RT
Adjustment
No Day Ahead Schedule, RT
create before NDL, RT Adj to
0
0
Assume
Negative
CCF =
Help if Increased Supply, Hurt if Decreased Supply
Change/
Created& OATI RT NDL DEV. RT. DEV.
Approved Volume Vol.
Volume
100
100
0
100
100
100
0
0
0
0
0 100
0
0 100
0
-1
NDL CMC RT CMC
NDL DEV
RT DEV Vol DDC Vol
DEV Vol DEV Vol CMC Vol VOL
0
100
0
-100
0
0
-100
0
0
0
0
100
0
0
0
0
100
100
0 100
0
-100
0
100
100
0
100
100
100
0 100
-100
0
100
0
100
100
0
100
100
0
-100
100
100
0
100
100
100
200
0
300
RT_RSG_DIST
Wheel Through Scenario
Approved Volume Scenario
Change Prior to NDL
11:00 AM
Day Prior
Day
Ahead Change/
Clearin Created &
g
Approved NDL
Assume
CCF =
-1
Change After
to NDL
Negative Help if Increased Supply, Hurt if Decreased Supply
Change/ OATI
Created& RT
Approved Vol.
RT.
NDL
DEV.
DEV. Vol. Vol.
NDL
CMC
DEV
Vol.
RT
CMC
DEV
Vol.
CMC
Vol.
NDL
DEV
Vol.
RT
DEV DDC
Vol. Vol.
Wheel
Through
Import
Export
Day Ahead
Schedule
Curtail/adjus
ted After
NDL to zero
100
100
100
0
0
0
-100
0
100
100
0
100
100
100
0
0
0
100
0
0
0
0
Note:
* CMC Dev. Import and Export could be in two different ATC; therefore the CMC volume could be
double if the import CCF is equal and opposite of export CCF.
* No DDC volume for wheel-through.
301
RT_RSG_DIST1 – Hierarchy
•
Intermediate Calculations for CMC_DEV_VOL and ATC_CMC_RATE are in
Section A.1.2 of the Calculation Guide.
302
RT_RSG_DIST1
• Constraint Management Charge Distribution
Calculation (CMC_DIST)
• Funds Real-Time RSG MWP amount credits paid to units
committed in the RAC to manage Active Transmission
Constraints (ATCs).
• AO’s assets and schedules with an adverse impact on a
constraint are charged based on the amount of deviation and the
Constraint Contribution Factor for the ATC.
• Calculates deviations from the Day-Ahead to the Notification
Deadline.
• Calculates deviations from the Notification Deadline to the RealTime.
303
RT_RSG_DIST1 – Formula
Intermediate Calculations
Constraint Management Charge Distribution
*CMC_DIST
=Σ
ATC
(ATC_CMC_DIST_HR)
Hourly Constraint Management Distribution
ATC_CMC_DIST_HR
=
(CMC_DEV_VOL * ATC_CMC_RATE)
304
RT_RSG_DIST1 – Formula
Intermediate Calculations
*CMC_DEV_VOL
Determinant
CMC_NDL_PHYS_IMP_VOL
Hourly Active Transmission Constraint Management Charge Deviation Volume
= MAX ( CMC_NDL_MR_VOL + CMC_NDL_DR_VOL + CMC_NDL_LOAD_VOL +
CMC_NDL_VIRT_VOL + CMC_NDL_PHYS_IMP_VOL + CMC_NDL_PHYS_EXP_VOL +
CMC_NDL_FIN_VOL + CMC_NDL_DRR1_VOL + CMC_NDL_NDSP_VOL, 0 ) +
CMC_RT_MR_VOL + CMC_RT_DR_VOL + CMC_RT_EXE_DFE_VOL +
CMC_RT_LOAD_VOL + CMC_RT_PHYS_IMP_VOL + CMC_RT_PHYS_EXP_VOL +
CMC_RT_DRR1_VOL + CMC_RT_NDSP_VOL
Description
Hourly Constraint Management Charge Notification Deadline Physical Import Imbalance
Volume (MWh)
= IF DEV_EXEMPT_PHYSSchd_ID = ’Y’ THEN 0 ELSE ( NDL_PHYSSeller - DA_PHYSSeller ) *
CCF
CMC_NDL_PHYS_EXP_VOL
Hourly Constraint Management Charge Notification Deadline Physical Export Imbalance
Volume (MWh)
= IF DEV_EXEMPT_PHYS = ‘Y’ THEN 0 ELSE ( DA_PHYSBuyer – NDL_PHYSBuyer ) * CCF
CMC_RT_PHYS_IMP_VOL
Hourly Constraint Management Charge Real-Time Physical Import ImBalance Volume (MWh)
= IF DEV_EXEMPT_PHYS = ‘Y’ THEN 0 ELSE MAX ( [ RT_PHYSSeller - NDL_PHYSSeller ] *
CCF , 0 )
CMC_RT_PHYS_EXP_VOL
Hourly Constraint Management Charge Real-Time Physical Export Imbalance Volume (MWh)
= IF DEV_EXEMPT_PHYS = ‘Y’ THEN 0 ELSE MAX ( [ NDL_PHYSBuyer - RT_PHYSBuyer ] *
CCF , 0 )
305
RT_RSG_DIST1 – Formula
Intermediate Calculations
Hourly Active Transmission Constraint Management Charge Rate ($/MWh)
*ATC_CMC_RATE
= ATC_CMC_MWP / MAX ( ATC_CMC_DEV_VOL +
ATC_CMC_TA_TDR_VOL, ATC_CMC_MAX_DSP_VOL )
Determinant
Description
ATC_CMC_MWP
Hourly Active Transmission Constraint Management Charge MWP ($)
ATC_CMC_DEV_VOL
Hourly Active Transmission Constraint Management Charge Deviation Volume (MWh)
ATC_CMC_TA_TDR_VOL
Hourly Active Transmission Constraint Management Charge Topology
Adjustment/Transmission De-rate Volume (MWh)
= ∑ATC ( IF CANCEL_FL = ‘Y’ THEN 0 ELSE ( RT_RSG_ASSET_CR_HR*( -1 ) )* ( MIN (
CCF,0 ) * -1 ) )
= ∑ ATC ( CMC_DEV_VOL)
Represents the total Megawatt volume of Topology Adjustments or
Transmission De-rates for a given Active Transmission Constraint.
ATC_CMC_MAX_DSP_VOL
Hourly Active Transmission Constraint Management Charge Maximum Dispatch Volume
(MWh)
= ∑ RAC_ATC ( RT_MAX_DSP * ( MIN ( CCF, 0 ) * -1 ) )
306
RT_RSG_DIST1 – Example
Scenario
•
•
•
•
•
•
Per our Day-Ahead example total imports are 80 MW and total exports are 125 MW.
Per our Real-Time example total imports are 100 MW and total exports are 100 MW.
For HE1 the Notification Deadline imports is 80 MW and the Notification Deadline
exports is 125 MW.
The CCFnode-export is -.5 and CCFnode-import is .075
The ATC_CMC_RATEnode-import is 10.19 and ATC_CMC_RATEnode-export is 15.19
What is the CMC_DIST?
CMC_DIST
HE
DA_PHYSSeller
DA_PHYSBuyer
RT_PHYSSeller
RT_PHYSBuyer
1
80
125
100
100
HE
NDL_PHYSSeller
NDL_PHYSBuyer
CCF
ATC_CMC_RATE
1
80
125
-.5, .75
10.19 and 15.19
307
RT_RSG_DIST1 – Example
Intermediate Calculations
Determinant
Description
CMC_NDL_PHYS_IMP_VOL
Hourly Constraint Management Charge Notification Deadline Physical Import Imbalance
Volume (MWh)
= IF DEV_EXEMPT_PHYSSchd_ID = ’Y’ THEN 0 ELSE ( NDL_PHYSSeller - DA_PHYSSeller ) *
CCF
0
CMC_NDL_PHYS_EXP_VOL
= (80 – 80)* -.5
Hourly Constraint Management Charge Notification Deadline Physical Export Imbalance
Volume (MWh)
= IF DEV_EXEMPT_PHYS = ‘Y’ THEN 0 ELSE ( DA_PHYSBuyer – NDL_PHYSBuyer ) * CCF
0
=(125-125)*.075
Hourly Constraint Management Charge Real-Time Physical Import ImBalance Volume (MWh)
CMC_RT_PHYS_IMP_VOL
= IF DEV_EXEMPT_PHYS = ‘Y’ THEN 0 ELSE MAX ( [ RT_PHYSSeller - NDL_PHYSSeller ] *
CCF , 0 )
0
CMC_RT_PHYS_EXP_VOL
=MAX([100-80]* -.5, 0)
Hourly Constraint Management Charge Real-Time Physical Export Imbalance Volume (MWh)
= IF DEV_EXEMPT_PHYS = ‘Y’ THEN 0 ELSE MAX ( [ NDL_PHYSBuyer - RT_PHYSBuyer ]
* CCF , 0 )
1.875
=MAX([125-100]*.075,0)
308
RT_RSG_DIST1 – Formula
Intermediate Calculations
*CMC_DEV_VOL
*CMC_DEV_VOL
*CMC_DEV_VOL
Hourly Active Transmission Constraint Management Charge Deviation Volume
= MAX ( CMC_NDL_MR_VOL + CMC_NDL_DR_VOL + CMC_NDL_LOAD_VOL +
CMC_NDL_VIRT_VOL + CMC_NDL_PHYS_IMP_VOL + CMC_NDL_PHYS_EXP_VOL +
CMC_NDL_FIN_VOL + CMC_NDL_DRR1_VOL + CMC_NDL_NDSP_VOL, 0 ) +
CMC_RT_MR_VOL + CMC_RT_DR_VOL + CMC_RT_EXE_DFE_VOL +
CMC_RT_LOAD_VOL + CMC_RT_PHYS_IMP_VOL + CMC_RT_PHYS_EXP_VOL +
CMC_RT_DRR1_VOL + CMC_RT_NDSP_VOL
= MAX ( 0 + 0 + 0 + 0+ 0 +0 + 0 + 0 + 0, 0 ) + 0 + 0 + 0 + 0 + 0+
1.875 + 0 + 0
=
1.875 MW
309
RT_RSG_DIST1 – Formula
Intermediate Calculations
Hourly Constraint Management Distribution
ATC_CMC_DIST_HR
=
(CMC_DEV_VOL * ATC_CMC_RATE)
ATC_CMC_DIST_HR
=
(1.875 * 15.19)
ATC_CMC_DIST_HR
=
$28.48
310
RT_RSG_DIST1 – Formula
Intermediate Calculations
Constraint Management Charge Distribution
*CMC_DIST
*CMC_DIST
=Σ
=
ATC
(ATC_CMC_DIST_HR)
$28.48
311
RT_RSG_DIST1 – Hierarchy
•
Intermediate Calculations for CMC_DEV_VOL and ATC_CMC_RATE are in
Section A.1.2 of the Calculation Guide.
312
RT_RSG_DIST1
• Day-Ahead Deviation and Headroom Charge
Distribution Calculation (DDC_DIST)
• Charges Asset Owners for asset-related deviations and demand
changes for RAC-Committed Resources.
• Calculates deviations from Day-Ahead to the Notification
Deadline.
• Calculates deviations from the Notification Deadline to RealTime.
313
RT_RSG_DIST1 – Formula
Intermediate Calculations
Hourly Day-Ahead Deviation and Headroom Charge Distribution Amount ($)
*DDC_DIST
= DDC_DEV_VOL * MISO_DDC_RATE
314
RT_RSG_DIST1 – Formula
Intermediate Calculations
*DDC_DEV_VOL
Determinant
DDC_NDL_PHYS_IMP_VOL
Hourly Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh)
= MAX ( DDC_NDL_CAP_VOL + DDC_NDL_LOAD_VOL + DDC_NDL_PHYS_IMP_VOL
+ DDC_NDL_PHYS_EXP_VOL + DDC_NDL_VIRT_VOL + DDC_NDL_FIN_VOL +
DDC_NDL_DRR1_VOL + DDC_NDL_NDSP_VOL, 0 ) + DDC_RAC_DR_VOL +
DDC_RAC_MR_VOL + DDC_RT_DR_VOL + DDC_RT_MR_VOL +
DDC_RT_EXE_DFE_VOL + DDC_RT_LOAD_VOL + DDC_RT_PHYS_IMP_VOL +
DDC_RT_PHYS_EXP_VOL + DDC_RT_DRR1_VOL + DDC_RT_NDSP_VOL
Description
Hourly Day-Ahead Deviation and Headroom Charge Notification Deadline Physical Import
Imbalance Volume (MWh)
= IF DEV_EXEMPT_PHYS = ’Y’ THEN 0 ELSE (DA_PHYSSeller – NDL_PHYSSeller )
DDC_NDL_PHYS_EXP_VOL
Hourly Day-Ahead Deviation and Headroom Charge Notification Deadline Physical Export
Imbalance Volume (MWh)
= IF DEV_EXEMPT_PHYS = ‘Y’ THEN 0 ELSE ( NDL_PHYSBuyer - DA_PHYSBuyer )
DDC_RT_PHYS_IMP_VOL
Hourly Day-Ahead Deviation and Headroom Charge Real-Time Physical Import Imbalance
Volume (MWh)
= IF DEV_EXEMPT_PHYS = ‘Y’ THEN 0 ELSE ABS ( NDL_PHYSSeller - RT_PHYSSeller )
DDC_RT_PHYS_EXP_VOL
Hourly Day-Ahead Deviation and Headroom Charge Real-Time Physical Export Imbalance
Volume (MWh)
= IF DEV_EXEMPT_PHYS = ‘Y’ THEN 0 ELSE ABS ( RT_PHYSBuyer - NDL_PHYSBuyer
315
RT_RSG_DIST1 – Formula
Intermediate Calculations
Hourly MISO Day-Ahead Deviation and Headroom Charge Rate ($/MWh)
*MISO_DDC_RATE
= ( MISO_RT_RSG_MWP – MISO_CMC_DIST –
MISO_CMC_TA_TDR_DIST ) / MAX { MISO_DDC_DEV_VOL +
MIN ( HEADROOM , MISO_RAC_MAX_DSP_VOL ) ,
(MISO_RAC_MAX_DSP_VOL - MISO_CMC_MAX_DSP_VOL)}
Determinant
*MISO_RT_RSG_MWP
Description
Hourly MISO Real-Time RSG MWPs Total Amount ($)
=∑ MISO RAC ( IF CANCEL_FL = ‘Y’ THEN 0 ELSE RT_RSG_ASSET_CR_HR * ( -1 ) )
*MISO_CMC_DIST
Hourly MISO Constraint Management Charge Distribution Amount ($)
*MISO_CMC_TA_TDR_DIST
Hourly MISO Constraint Management Charge Topology Adjustment/Transmission De-rate
Charge Distribution Amount ($)
= ∑ MISO ATC ( CMC_DIST_HR )
= ∑MISO ATC ( ATC_CMC_TA_TDR_DIST )
*MISO_DDC_DEV_VOL
Hourly MISO Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh)
= ∑AO ( DDC_DEV_VOL )
316
RT_RSG_DIST1 – Formula
Intermediate Calculations
Determinant
Description
*HEADROOM
Hourly Headroom Volume (MWh)
*MISO_RAC_MAX_DSP_VOL
Hourly MISO RAC Maximum Disptach Volume (MWh)
*MISO_CMC_MAX_DSP_VOL
Hourly MISO Constraint Management Charge Maximum Dispatch Volume (MWh)
= ∑MISO ( RT_MAX_DSP – [ -1 * AEI ] )
= ∑ MISO RAC ( RT_MAX_DSP )
= ∑ RAC_ATC ( RT_MAX_DSP * ( MIN ( CCF, 0 ) * -1 ) )
317
RT_RSG_DIST1 – Example
Scenario
• Per our Day-Ahead example total imports are 80 MW and total
exports are 125 MW.
• Per our Real-Time example total imports are 100 MW and total
exports are 100 MW.
• For HE1 the Notification Deadline imports is 80 MW and the
Notification Deadline exports is 125 MW.
DDC_DIST
DA_PHYSSeller
• HE
DDC_DIST
DA_PHYSBuyer
RT_PHYSSeller
RT_PHYSBuyer
100
1
80
125
100
HE
NDL_PHYSSeller
NDL_PHYSBuyer
MISO_DDC_
RATE
1
80
125
$1.78
318
RT_RSG_DIST1 – Formula
Intermediate Calculations
Determinant
Description
Hourly Day-Ahead Deviation and Headroom Charge Notification Deadline Physical Import
Imbalance Volume (MWh)
DDC_NDL_PHYS_IMP_VOL
= IF DEV_EXEMPT_PHYS = ’Y’ THEN 0 ELSE (DA_PHYSSeller – NDL_PHYSSeller )
0
DDC_NDL_PHYS_EXP_VOL
= (80 – 80)
Hourly Day-Ahead Deviation and Headroom Charge Notification Deadline Physical Export
Imbalance Volume (MWh)
= IF DEV_EXEMPT_PHYS = ‘Y’ THEN 0 ELSE ( NDL_PHYSBuyer - DA_PHYSBuyer )
0
= (125 – 125)
Hourly Day-Ahead Deviation and Headroom Charge Real-Time Physical Import Imbalance
Volume (MWh)
DDC_RT_PHYS_IMP_VOL
= IF DEV_EXEMPT_PHYS = ‘Y’ THEN 0 ELSE ABS ( NDL_PHYSSeller - RT_PHYSSeller )
20
DDC_RT_PHYS_EXP_VOL
= ABS (80 - 100)
Hourly Day-Ahead Deviation and Headroom Charge Real-Time Physical Export Imbalance
Volume (MWh)
= IF DEV_EXEMPT_PHYS = ‘Y’ THEN 0 ELSE ABS ( RT_PHYSBuyer - NDL_PHYSBuyer
25
= ABS (100 – 125)
319
RT_RSG_DIST1 – Formula
Intermediate Calculations
*DDC_DEV_VOL
Hourly Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh)
= MAX ( DDC_NDL_CAP_VOL + DDC_NDL_LOAD_VOL + DDC_NDL_PHYS_IMP_VOL
+ DDC_NDL_PHYS_EXP_VOL + DDC_NDL_VIRT_VOL + DDC_NDL_FIN_VOL +
DDC_NDL_DRR1_VOL + DDC_NDL_NDSP_VOL, 0 ) + DDC_RAC_DR_VOL +
DDC_RAC_MR_VOL + DDC_RT_DR_VOL + DDC_RT_MR_VOL +
DDC_RT_EXE_DFE_VOL + DDC_RT_LOAD_VOL + DDC_RT_PHYS_IMP_VOL +
DDC_RT_PHYS_EXP_VOL + DDC_RT_DRR1_VOL + DDC_RT_NDSP_VOL
Hourly Day-Ahead Deviation and Headroom Charge Deviation Volume (MWh)
= MAX (0 + 0 + (0) +) (0) + 0 + 0 + 0 + 0, 0 ) + 0 + 0 + 0 + 0 + 0 + 0 + (20) + (25) + 0 + 0
*DDC_DEV_VOL
*DDC_DEV_VOL
= 45 MW
320
RT_RSG_DIST1 – Formula
Intermediate Calculations
Hourly Day-Ahead Deviation and Headroom Charge Distribution Amount ($)
*DDC_DIST
= DDC_DEV_VOL * MISO_DDC_RATE
Hourly Day-Ahead Deviation and Headroom Charge Distribution Amount ($)
*DDC_DIST
= 45 MW * $1.78
*DDC_DIST
= $80.10
321
RT_RSG_DIST1 – Hierarchy
322
RT_RSG_DIST1 - Formula
Hourly Real-Time RSG Distribution Amount
*RT_RSG_DIST1_HR
=
CMC_DIST + DDC_DIST
Hourly Real-Time RSG Distribution Amount
*RT_RSG_DIST1_HR
=
$28.48+ $80.10
*RT_RSG_DIST1_HR
=
$ 108.58
323
RT_RSG_DIST1 - Formula
*RT_RSG_DIST1
H
$108.98
(
*RT_RSG_DIST1_HR
)
(
$108.98
)
=∑
=∑
H
Results in a $108.98 charge for HE 1
324
RT_RSG_DIST1 – Summary
• The Real-Time Revenue Sufficiency Guarantee First Pass
Distribution Amount funds the RSG Make Whole Payments paid to
the generation asset owners
• This charge type issues a charge to AOs for the total market-wide
Make Whole Payment amount based on real-time Load, Generation,
Virtual Supply and Physical Bilateral Transaction deviations from DA
• This amount is calculated hourly for an AO by adding the Constraint
Management Charge Distribution and the Day-Ahead Deviation and
Headroom Charge Distribution Amount.
Questions?
325
Real-Time Credits and Charges
Real-Time Credits and Charges
Charge Type
Schedule Type
Credit Amount
Charge Amount
RT_NASSET_EN
RT_ADMIN
Import, Export, WheelThrough
Import, Export
$-1090.00
$0.00
$0.00
$4.41
RT_SCHD_24_ALC
Import, Export
$0.00
$.50
RT_NI_DIST
Import, Export
$0.00
$80.25
RT_RNU
Import, Export
$0.00
$18.75
RT_ASM_SPIN_DIST
Export, Wheel-Through
$0.00
$2.00
RT_ASM_SUPP_DIST
Export, Wheel-Through
$0.00
$1.00
RT_RSG_DIST1
Import, Export, WheelThrough
$0.00
$108.58
Total Credits/Charges
$-1090.00
$215.10
Result-Credit
$-874.90
326
Questions ?
Review Test
Question 1
• If the Source Point is internal to the MISO
Market Footprint and the Sink Point is
external the Interchange Schedule is what
type?
A.
B.
C.
D.
Export Schedule
Import Schedule
Through Schedule
Grandfathered Carve Out Schedule
329
Question 2
• This is the standard energy type. The hourly
MW amount is static and does not change
after the fact?
A.
B.
C.
D.
Dynamic
Fixed
Dispatchable
Normal
330
Question 3
• This Market Type clears ahead of the operating day
and is financially binding on Market Participants?
A. Real-Time Energy and Operating Reserve Market
B. Financial Transmission Right Operating Reserve
Market
C. Day-Ahead Energy and Operating Reserve Market
D. All of the above
331
Question 4
• A reservation is created in _____ by
completing a Transmission Service Request?
A. Open Access Technology Inc (OATI)
B. Open Access Same-Time Information System
(OASIS)
C. Physical Scheduling System (PSS)
D. DART
332
Question 5
• The ____ for Import, Export and Through Schedules
is determined at the external commercial pricing
nodes where energy is being imported and exported
from the MISO market?
A.
B.
C.
D.
Charge Type
Asset Owner
LMP
Energy Type
333
Question 6
• Represents the AO’s daily Day-Ahead net energy
cost (or credit) related to Commercial Pricing
Nodes where the AO does not own assets for that
Operating Day?
A.
B.
C.
D.
Day-Ahead Market Administration Amount
Day-Ahead Non-Asset Energy Amount
Day-Ahead Schedule 24 Allocation Amount
Day-Ahead Revenue Sufficiency Guarantee
Distribution Amount
334
Question 7
• Hourly Day-Ahead Non-Asset Energy Amount
(DA_NASSET_EN_HR) is calculated by
multiplying?
A.
B.
C.
D.
The DA_PHYS_VOLBuyer * DA_LMP
The DA_NASSET_EN * DA_LMP
The DA_PHYS_VOLSeller * DA_LMP
The DA_NASSET_VOL * DA_LMP
335
Question 8
• The DA_ADMIN uses the ______ Rate and the
DA_SCHD_24_ALC uses the ______ Rate to determine their
charges/credits?
A. Schedule 24 Allocation Rate and Day-Ahead and
Real-Time Administrative Rate (Schedule 17)
B. Day-Ahead and Real-Time Administrative Rate
(Schedule 17) and Schedule 24 Allocation Rate
C. Day-Ahead and Real-Time Administrative Rate
(Schedule 17) and FTR Administrative Rate
D. FTR Administrative Rate and Day-Ahead and
Real-Time Administrative Rate (Schedule 17)
336
Question 9
• When calculating the RT_RSG_DIST1 and
considering wheel through schedule is 100 MW,
the DDC Volume is
A.
B.
C.
D.
100 MW
200 MW
0 MW
None of the above
337
Question 10
• When calculating RT_NASSET_EN and
considering Physical Bilateral Transactions only
the RT_NASSET_VOL is calculated by?
A.
B.
C.
D.
DA_PHYS_VOLNet - RT_PHYS_VOLNet
RT_LMP * RT_PHYS_VOLNet
RT_LMP * DA_PHYS_VOLNet
RT_PHYS_VOLNet - DA_PHYS_VOLNet
338
Question 11
• Which MISO Day Ahead Charge Amount accounts
for the energy value of the Physical Bilateral
Transaction
A.
B.
C.
D.
DA_NASSET_EN
DA_ASSET_EN
DA_RSG_EN
DA_SCHD_EN
339
Question 12
• PSE-WIN wants to buy power from a generator near CIN HUB
and sell the power to PJM. PSE-WIN scheduled the E-tag from
the Source at CINgenerator to Sink is PJM. Which LMP would this
Schedule settle at?
A.
B.
C.
D.
CIN HUB LMP
Generator CP Node LMP
PJM Interface LMP
WIN offer price
340
Question 13
• If a RT physical schedule was curtailed by PJM due
to TLR, the MP may be subject to the following
charges
A.
B.
C.
D.
RT_ADMIN
RT_NASSET_EN
RT_RSG_DIST
All the above
341
Question 14
• This Charge Type is set up as a revenue distribution
balancing mechanism for charges and credits attributable to
load or that have no other distribution method to AOs?
A. Real-Time Net Inadvertent Distribution (RT_NI)
B. Real-Time Schedule 24 Distribution Amount
(RT_SCHD_24_DIST)
C. Real-Time Non-Asset Energy (RT_NASSET_EN)
D. Real-Time Revenue Neutrality Uplift Amount
(RT_RNU)
342
Question 15
• When calculating the RT_ASM_SPIN_DIST the
ASM_SPIN_DIST_VOLCN uses the sum of the Physical
Bilateral Transactions?
A.
B.
C.
D.
Exports/RT_PHYSBuyer
Imports/RT_PHYSSeller
Exports/RT_PHYSBuyer - Imports/RT_PHYSSeller
Exports/RT_PHYSBuyer + Imports/RT_PHYSSeller
343
Question 16
• Which of the following is only a Day Ahead
Schedule?
A.
B.
C.
D.
GFACO
Fixed
Dispatchable
ALL
344
Question 17
• If an Real-Time Import Tag was curtailed by MISO,
what charges could be expected?
A.
B.
C.
D.
RT_NASSET_EN
RT_RSG_DIST1
RT_ADMIN
All the above
345
Question 18
• The new RSG_DIST1 Rate is
A.
B.
C.
D.
MISO_DDC_RATE
ATC_CMC_RATE
MISO_DDC_RATE + ATC_CMC_RATE
None of the above
346
Helpful Resources
References
• Settlement related documentation
– Posted on the MISO website (www.midwestiso.org):
• BPM 007 Physical Scheduling
• BPM 005 Market Settlements
• BPM 005 Market Settlements Attachment A
• BPM 012-Transmission Settlements
• BPM 017-Transimission Settlements Billing Dispute Resolution
• BPM 020-Monthly Transmission Billing
• http://www.midwestiso.org/Library/BusinessPracticesManuals/Pages/BusinessPr
acticesManuals.aspx
• Market Settlements helpful documents and files
• Market Settlements Working Group (MSWG) Meetings
• Conducted monthly, generally the First or Second Tuesday of every month
348
Helpful Resources
• Where can I learn about the Midwest Market?
– Websites
• www.midwestiso.org
• http://extranet.midwestiso.org
– Documentation
• On www.midwestiso.org
– Guiding documents – Business Practices, Draft Tariff
– Informational documents – Training presentations, Testing documentation, etc.
– Technical Infrastructure documents – Implementation documents
– Technical specifications
– Testing information
– Market Registration documents – Registration packet, public data
– Client Account Representative are assigned to each Market
Participant
349
Reporting Issues and Submitting Questions
• Client Relations
–
–
–
–
Call - 866-296-6476, Option 1
Email [email protected]
Email [email protected]
Email [email protected]
• Network Operations Center (NOC)
– Call - 866-296-6476, Option 2
• Report Portal, Dispatch and AGC Outages 24x7
• Report other items during MISO business hours
350
RT_RSG_DIST1 Training
351
RT_RSG_DIST1 Training
352
Answer Key for Review Questions
1. C
2. D
3. D
4. A
5. C
6. C
7. D
8. D
9. C
10. D
11. C
12. B
13. B
14. A
15. C
16. A
353
Answer Key for Test Questions
1. A
2. D
3. C
4. B
5. C
6. B
7. D
8. B
9. A
10. D
11. A
12. C
13. D
14. D
15. A
16. C
17. D
18. D
354
Market Settlement Training Series
Market Settlements Training Modules:
–
–
–
–
–
–
–
–
Overview O101
ARR/FTR AF201
Virtual and Financial Schedules VF201
Physical Schedules PS201
Load L201
Generation G201
Generation Wind Farm GWF202
Overview O101
(Feb. 2011)
(Mar. 2011)
(Apr. 2011)
(May 2011)
(Jul. 2011)
(Aug. 2011)
(Sep. 2011)
(Oct. 2011)
355
Thank You for Attending
Please Fill out the Survey 
356