MISO ARR/FTR Modeling Practices
MO-OP-019-r6
Effective Date: APR-23-2017
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Purpose ................................................................................................................... 2
Scope ....................................................................................................................... 2
Definitions ............................................................................................................... 2
Roles and Responsibilities .................................................................................... 3
Procedure Description ........................................................................................... 3
5.1 Network Topology .............................................................................................. 3
5.2 Contingencies .................................................................................................... 4
5.3 Operating Guides ............................................................................................... 5
5.4 Monitored Branch Constraints ............................................................................ 6
5.5 Monitored Flowgate Constraints......................................................................... 7
5.6 Phase Angle Regulator (PAR) Settings............................................................. 8
5.7 Loopflow Assumptions ....................................................................................... 8
5.8 Nomograms........................................................................................................ 9
5.9 Scheduled Outages.......................................................................................... 10
6 References ............................................................................................................ 10
7 Disclaimer ............................................................................................................. 10
8 Revision History ................................................................................................... 11
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MISO ARR/FTR Modeling Practices
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Purpose
This document describes the modeling approaches for various elements of the MISO
FTR model used in the Simultaneous Feasibility Test for Annual ARR Allocations and
FTR Auctions.
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Scope
This procedure applies to the approaches for various elements of the MISO FTR model
used for Auction Revenue Right (ARR) allocations and Financial Transmission Right
(FTR) Auctions. The Policy applies to the FTR and Pricing Administration (FPA), which
administers the FTR and ARR markets.
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Definitions
ARR: Auction Revenue Right
BA: Balancing Authority Area
CBM: Capacity Benefit Margin
CPNode: Commercial Pricing Node
DA/RT: Day-Ahead and Real-Time Energy and Operating Reserve Market
EMS: Energy Management System
FFE: Firm Flow Entitlements
FPA: FTR and Pricing Administration
FTR: Financial Transmission Right
ICCP: Inter-Control Center Protocol
IDC: Interchange Distribution Calculator
JOA: Joint Operating Agreement (also known as Seams Agreement)
LBA: Local Balancing Authority
LBA Area: Local Balancing Authority Area
LF: Loop Flow
LF ARR: Loop Flow Auction Revenue Right
MOD: Model on Demand
OTDF Flowgate: Outage Transfer Distribution Factor flowgate (with contingency)
PAR: Phase Angle Regulator
PTDF Flowgate: Power Transfer Distribution Factor flowgate (without contingency)
RCF: Reciprocal Coordinated Flowgates
RTCA: Real Time Contingency Analysis
RTO: Regional Transmission Organization
SFT: Simultaneous Feasibility Test
TO: Transmission Owners
TRM: Transmission Reliability Margin
TTC: Total Transfer Capability
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Roles and Responsibilities
FPA is responsible for administering the ARR/FTR markets, which require building,
posting and using models as described in this document.
5
Procedure Description
This procedure describes the modeling approaches for various elements of the MISO
FTR model used in the Simultaneous Feasibility Test for Auction Revenue Right (ARR)
allocations and Financial Transmission Right (FTR) Auctions.
5.1
Network Topology
ARR/FTR analysis utilizes a bus-branch Network Model that is derived from a nodebreaker model maintained in the EMS environment. HEDGE™ software used in the
ARR/FTR analysis can read the bus-branch model in the PSS/E format.
The EMS model is utilized in MISO’s Reliability Coordination applications such as State
Estimator and Contingency Analysis. This model is continuously reviewed and updated
with the help of MISO’s transmission owning members. A significant portion of the U.S.
Eastern Interconnection electricity grid is represented in this model. Real-time ICCP
measurements on generation, load, flow, breaker status etc. are obtained and applied
on the model.
The MISO EMS system is based on Alstom’s Habitat/WebFG environment. The
ARR/FTR model is created through the following steps:
1) A current snapshot of the model from the EMS environment is created.
2) Future equipment is incorporated by adding new facilities, removing/outaging
the equipment to be retired and implementing network reconfigurations
provided by the TO prior to the published deadline. 1
a. Modeling future topology changes: Incorporate new facilities utilizing
the information from MISO Model on Demand (MOD) tool and as
submitted by the TO through other means of communication. The new
facility will be double modeled or configured as a dummy equipment to
represent the topology change until the facility is placed in-service.
b. Retirement: Remove/open equipment to be retired utilizing the
information submitted to MISO by the TO, primarily but not exclusively
through MISO Web-tool.
c. Network configuration: Incorporate line impedances and ratings
utilizing the information submitted through MISO Web-tool and as
submitted by TO through other means of communication.
1
Per IRO-010 R3, all modeling information must be submitted in accordance with the MISO IRO-010 R1 Data
Specification: RTO-SPEC-006 MISO Reliability Data Specification, Section 3.1 System Modeling and Parameters and
within the MISO established modeling timeframe.
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3) The circuit breakers and switches are positioned at their nominal status, but
normally open devices may be closed to connect loads or generators as
necessary.
4) The bus numbers, PTI bus names and area numbers are mapped to the
same numbers and names in an IDC case to the extent possible.
5) MISO reserves the right to make adjustments deemed appropriate and
adequate to represent the model based on the best available data when
differences exist in the information provided by the TO through various
systems. Therefore, the model may be similar but not necessarily identical to
the individual TO’s real-time or planning models.
6) Powerflow is executed to ensure relevant facilities are energized and a solved
system state is achieved in the EMS powerflow environment.
5.2
Contingencies
The following criteria are applied to define contingencies for ARR/FTR Simultaneous
Feasibility Test (SFT):
• Contingencies associated with OTDF flowgates in the AFC models are
selected if
o The flowgate is internal to the MISO footprint and/or
o The flowgate is included in the list of the Reciprocal Coordinated
Flowgates (RCF) from the Joint Operating Agreements with PJM; SPP
and other entities. 2
• Non-flowgate contingencies are added only under the following conditions
o If it is identified that existing flowgate contingencies do not adequately
represent N-1 operating conditions.
o If a non-flowgate contingency is identified to cause overloads in realtime or day ahead operations or being active in RTCA.
• External lines and transformers that are not associated with RCF are not
included in the contingency list.
• Contingencies that have operating guides are modeled assuming the
operating guides are implemented.
2
These entities include EKPC, TVA, and LGEE.
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5.3
Operating Guides
Operating guides provide real time operations with a means of mitigating overloads that
may result from unforeseen system conditions or influences external to the MISO
market. In some cases operating guides may be developed in response to a planned
system outage of transmission or generation facilities. Operating guide development is
coordinated by the MISO reliability operations engineering group in cooperation with the
affected equipment owners.
MISO FTR markets include the use of available operating guides in FTR market
analysis where conditions exist that necessitate the use of a mitigation plan. When an
operating guide is available, the ARR/FTR market considers the mitigation steps that
involve system reconfiguration or reductions in facility limits due to operational issues.
Where operating guides eliminate transmission constraints by ultimately removing the
overloaded facility from service, the constraint is excluded in the ARR/FTR analysis.
Although the implementation of operating guides is subject to system conditions, there
is no capability to define a conditional relaxation of constraints, and it is assumed that
the operating guide is implemented in real time. By considering the mitigating effects of
the operating guide, the results of the FTR market analysis typically result in fewer
constraints.
In some cases operating guides include voluntary redispatch steps. However, this
means of constraint relief is not modeled in the ARR/FTR analysis. Operating guides
that use dynamic ratings are problematic for the FTR model since the ratings are
dependent on environmental conditions that cannot accurately be predicted in advance.
ARR/FTR analysis uses published ratings while dynamic ratings are reserved for real
time operations. Where stability-related operating guides exist, the ARR/FTR analysis
software applies the stability limit to the base rating of the facility while the emergency
thermal limits are applied to the emergency rating of the facility for contingency analysis.
Table 1 below discusses the types of mitigation measures available in operating guides
and discusses how each guide is implemented in ARR/FTR analysis.
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Table 1
Mitigation Plan via Op.
Guide
No pre-contingency or atcontingency mitigation
Reconfigure System with
Known MW Relief
Reconfigure System with
Unknown MW Relief
Pre-contingency voluntary
redispatch
At-contingency voluntary
redispatch or Generator
Runback
Dynamic Ratings
Stability Limits
5.4
Implementation of Op. Guide in ARR/FTR models
None
Adjust limit by the amount of MW relief expected
One of the following methods is implemented on a
case-by-case basis:
a) Include reconfiguration in contingency definition, if
possible. If reconfiguration causes new violations,
choice is made between proceeding with or without
guide based on offline studies
b) If the guide is expected to relieve all overloads
associated with a specific contingency, the
contingency is ignored
c) If the guide relieves a specific constraint under a
particular contingency, the contingency-constraint
pair is ignored
d) If the guide relieves all overloads on a specific
constraint, the constraint is ignored
None
Selective modeling of runback if redispatch is effective;
otherwise contingency is ignored
Use published ratings available
Apply stability limit to the normal (base case) rating.
Use thermal emergency rating for the contingency limit.
Monitored Branch Constraints
Branch constraints are enforced in the following manner in the ARR/FTR models:
5.4.1 Transmission Lines
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All Local Balancing Authority (LBA) transmission lines at 100 KV and above are
constrained to their limits.
Each transmission line that is a tie between an LBA Area and tier 1 control area and
at voltage level 100 KV and above is constrained to its limits.
LBA and tie transmission lines below 100 KV may be monitored on a case-by-case
basis in order to ensure that largest angle across any lines or transformers is less
than 90 degrees.
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5.4.2 Transformers
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All LBA transformers with both ends at 100 KV and above are constrained to their
limits.
Each transformer that is a tie between an LBA Area and tier 1 control area and with
both ends at 100 KV and above is constrained to its limits.
3-winding transformers are constrained to their limits if they are internal or
connected to the footprint and if at least two ends are at 100 KV and above.
Internal and tie transformers below 100 KV may be monitored on a case-by-case
basis in order to ensure that largest angle across any lines or transformers is less
than 90 degrees.
5.4.3 Global Limit Set and Low kV Monitoring
The thermal and emergency ratings of the monitored transmission lines and
transformers are modeled at or above 90% of their original ratings. For modeling a
future Spring season, lines and transformers may be modeled at or above 85% of their
original ratings.
In LBAs where the MISO has reliability coordination function, transmission lines and
transformers are monitored at 69kV and above.
Any branch will be enforced and the limit set to twice its original limit if all the following
conditions are met:
1) The branch is connected to a bus where a single CPNode-EPNode is defined.
2) The sum of all the branches’ emergency limits connecting to this bus is less
than 100MW.
3) The branch does not meet the monitored branch inclusion criteria defined
above.
A few transmission lines and transformer constraints satisfying the above categories are
not enforced due to standing operating guides that include post-contingency mitigation
schemes. Operating guides modeling criteria are provided in a separate section in this
document.
5.5
Monitored Flowgate Constraints
All internal PTDF and OTDF flowgates owned by MISO and monitored in the MISO
security coordination process are enforced in the ARR/FTR process as obtained
through the MISO Flowgate update process. The flowgate ratings are enforced at or
above 90%, of their Total Transfer Capability (TTC). The TTC is not reduced for
Transmission Reliability Margin (TRM) and Capacity Benefit Margin (CBM).
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All external PTDF and OTDF flowgates that are part of the Reciprocal Coordinated
Flowgate (RCF) set are also enforced in the ARR/FTR process. These external RCFs
are modeled as generic constraints described in Section 5.8 Nomograms.
5.6
Phase Angle Regulator (PAR) Settings
HEDGE™ provides simple linear models for Phase Angle Regulator (PAR), also called
phase shifters, for use with DC analysis. Nonlinear PAR models are also possible but
the computational time would drastically increase since the process would need to
iterate and recalculate distribution factors at each iteration. Hence, linear network
models and DC analysis are used for ARR allocation and FTR Auction analysis.
Linearity of the optimization problem is maintained as long as each PAR is modeled
with a fixed phase angle or a fixed MW flow but not optimized in the solution process to
switch between modes.
The PAR model, including the initial angle setting, the angle and flow limits and the
impedance correction data, are specified in the network data. The PARs are modeled in
ARR/FTR analysis either at fixed angle and local control or optimized mode. The control
modes and parameter settings are determined based on feedback from transmission
providers regarding nominal operation of these phase shifters. Feedback from DA/RT
operations is also considered.
5.7
Loopflow Assumptions
Loop flows consist of the flows on the MISO footprint caused by external transactions.
The modeling of loopflow is to produce representative flows by explicitly modeling
transactions of external entities with a set of Point-to-Point fixed ARRs for tier 1 BAs.
These ARRs/FTRs are termed as Loop Flow (LF) ARRs/FTRs.
LF ARRs/FTRs are split into three groups:
1) Generation Loopflows – These represent the intra-BA network generation of
the tier 1 balancing areas. The source points for these transactions are
defined on generation loop flow nodes available in MISO’s Commercial Model
which are defined using generators of the corresponding tier 1 BA with its
Pmax as the weighting factors. The sink loop flow node representing all
generation loopflows will be chosen within the MISO Commercial Model,
traditionally a large HUB.
2) Load Loopflows – These represent the intra-BA network load of the tier 1
balancing areas. The sink points for these transactions are defined on load
loop flow nodes available in MISO’s Commercial Model which are defined
using load points of the corresponding tier 1 BA with its MW (from a specific
time stamp) as the weighting factors. The source loop flow node representing
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all load loopflows will be the node chosen as sink loop flow node for all
generation loopflows.
3) Interface Loopflows – These represent the net interchange of the tier 1
balancing areas. Depending on if the BA has a net negative or positive
interchange value, these loopflows will either source at the interface loopflow
nodes defined in MISO’s Commercial Model which are defined using
generators of the corresponding tier 1 BA with equal weighting factors, and
sink at the node chosen as sink loop flow node for all generation loop flow or
they will source at the node chosen as loop flow node for all generation loop
flow and sink at the interface loopflow node.
All generation, load, and interface loopflows will source or sink from the same HUB
node. Loopflow MWs are normalized in such a way as to ensure that the net
injection/withdrawal MW is equal to zero at the HUB node, which guarantees that the
choice of HUB node has no impact on the outcomes of the ARR/FTR SFT process.
These LF ARRs are modeled as fixed Obligations. The MW quantities are obtained from
the loopflow modeling in MISO’s Day-Ahead Market and seasonal planning models, as
appropriate.
5.8
Nomograms
Nomograms modeled in the FTR/ARR process are constraints that monitor and enforce
commercial flows, estimated from historical data, through the underlying monitored
elements under a certain contingency (or base case) in the definition. Flows from
loopflow modeling and other network modeling such as PARs etc., have no impact on
nomograms.
The day-ahead and real-time constraints are included as nomograms in the ARR/FTR
process when a non-trivial contribution to Day-Ahead and Real-Time Energy and
Operating Reserve Market (DA/RT) congestion, and/or FTR shortfall in a single season
during the year(s) before the upcoming allocation period, has occurred. In addition,
binding constraints that have non-trivial contribution to DA congestion and/or FTR
shortfall in the last few weeks just prior to the effective date of the allocations/auctions
will also be evaluated and included as needed. Various criteria include, but are not
limited to, total shadow price, total binding hours, total days of binding life span, etc.
Additional criteria may be used during the verification process and outage review to
identify and address constraints based on isolated events.
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Nomograms modeled in the FTR/ARR process represent the additional constraints that
are developed based on typically, the historical commercial flow during the hours when
they were binding in the DA/RT during the year before the upcoming allocation period. 3
In addition to constraints binding in the DA/RT markets, all the external RCFs will be
modeled as nomograms. The limits of such constraints are based on typically, the
historical MISO entitled commercial flow usage for the given flowgates during the year
before the upcoming allocation period.
5.9
Scheduled Outages
Scheduled outages are composed of outages from the MISO CROW system regardless
of the outages’ status (proposed, submitted, study, as well as accepted), pending
evaluation and review with DA/RT groups. In Annual ARR Allocation and Annual FTR
Auction, scheduled outages also include outages submitted by MISO Transmission
Owners as supplemental outages in response to the data request sent out by FTR and
Pricing Administration and Outage Coordination Group in order to better incorporate
future topology changes.
Any critical outages coming through internal or external notifications might be reviewed
by FTR and Pricing Administration and included in the ARR/FTR process at any time.
The scheduled outages inclusion criteria are determined as follows:
Seasonal Cases
• 5 calendar days or longer in the season
Monthly Cases
• 3 calendar days or longer in the month
Outages may have to be restored for various reasons that include but are not limited to:
1. When outages in different time frames within the same season cause an
islanding or phase islanding effect.
2. When the case solution cannot be reached due to multiple outages.
3. When PAR angles become extremely large.
6
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References
RTO-SPEC-006 Reliability Data Specification
7
Disclaimer
This document is prepared for informational purposes only to support the application of
the provisions of the MISO Tariff and the services provided thereunder. MISO may
revise or terminate this document at any time at its discretion without notice. While
3
Global limit reduction is not applied to generic constraints.
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every effort will be made by MISO to update this document and inform its users of
changes as soon as practicable, it is the user’s responsibility to ensure you are using
the most recent version of this document in conjunction with the MISO Tariff and other
applicable documents, including, but not limited to, the applicable NERC Reliability
Standards. Nothing in this document shall be interpreted to contradict, amend, or
supersede the MISO Tariff, and MISO is not responsible for any reliance on this
document by others, or for any errors or omissions or misleading information contained
herein. In the event of a conflict between this document, including any definitions, and
either the Tariff or a NERC standard, the Tariff or NERC Reliability Standard shall
prevail. In the event of a conflict between the Tariff and the NERC standard, the Tariff
shall prevail until or unless the Commission orders otherwise. Any perceived conflicts or
questions should be directed to the Legal Department.
8
Revision History
Doc Number
MO-OP-019-r6
MO-OP-019-r5
MO-OP-019-r4
MO-OP-019-r3
MO-OP-019-r2
Description
Annual Review completed
a) Revised language under section 5.4.2,
to describe a transformer that may be a
tie to an external LBA (in lieu of previous
description of jointly owned
transformers).
b) Made capitalization, terminology,
typographical and grammatical
corrections.
c) Specified primacy of Tariff definitions.
d) Deleted outdated reference to
MAPP.Added clarity to the node chosen
as the sink node for the Loopflow
assumptions
Annual Review completed.
a) Typographical errors
b) Revised limit requirements from 90% to
85% in section 5.4.3.
c) Clarified Network topology modeling
steps
d) Simplified description of outage
gathering criteria in Section 5.9, worded
as calendar days and removed
secondary criteria as it was included in
primary criteria description
Annual Review completed. Revised limit
requirements from 95% to 90% or greater in
section 6.4.3, Included the outage status of
proposed as an example of outages considered.
Access Level revised from Protected to Public.
Annual Review completed. No Changes.
Annual Review completed. Edited document for
Revised by:
N. Kirk
P.Nathan
Effective Date
APR-23-2017
N. Kirk
P. Nathan
APR-23-2016
N. Kirk
APR-23-2015
S. Singh
N. Kirk
APR-23-2014
APR-23-2013
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MO-OP-019-r1
MO-OP-019
Clarity
Revised the document, specifically for Generic
Constraints(changed to Nomograms), Loopflow
Assumptions and PARs sections
Original document
Xiaoming Wang
MAR-01-2012
Greg Leach
AUG-30-2011
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