1
2
3
Note: The Network Model referenced in this training and the BPM reflects only the
Network Model associated with the Integrated Control Center Systems (ICCS) and MISO
Market system applications. It does not refer to other power system models developed and
maintained by MISO to support functions such as long-range planning.
The Network Model and Commercial Model both provide essential information to the
DART and FTR models for accurate reliability, market, and analysis functions. In addition,
element parameters and asset meta-data are exchanged between the Network and
Commercial models. Each model’s accuracy is essential to MISO operation; how the
Commercial Model is created directly affects the market settlement function for each
Market Participant.
Network Model
• All Real-Time Reliability applications (such as the State Estimator and Real-Time
Contingency Analysis application) run on the network model
• The Real-Time Market and Day-Ahead Market applications (such as the Unit Dispatch
System and the Unit Commitment System) run on the network model
• The Operators’ Power Flow and other EMS Study applications run on the network model
• The Voltage Stability Analysis application runs on the network model
• The Base FTR models are derived from the network model
• The Dispatch Training Simulator application runs on a model that is built from the
network model
4
Commercial Model
• The commercial model is key input to the Real-Time Market and Day-Ahead Market
applications (such as the Unit Dispatch System and the Unit Commitment System)
• The commercial model is key input for the FTR systems
• The commercial model is key input to the Settlement systems
• The Dispatch Training Simulator application runs on a model that is built from the
commercial model
• The MISO stakeholders utilize the network model, commercial model and FTR model to
perform various market studies and analysis
• The Independent Market Monitor (IMM) uses the network and commercial model data to
provide critical functions in support of FERC, state regulators and the Midwest to ensure
the success of the wholesale electricity markets
<<Subsequent slides further define relationships and dependencies between the NM and
CM>>
4
5
The Network Model supports the Real-Time and study network analysis functions used to
determine the power system reliability and certain market operations functions that are
used to securely commit and dispatch generation, and the assessment of the availability of
FTRs. The Network Model is populated with data provided by authorized Transmission
Owners and MPs and provides a mathematical representation of the electric power system.
6
Splits
• Load is normally modeled within the physical boundary of a Balancing Authority
(BA) and is included in the Balancing Authority’s load calculation.
• Where necessary, we split the ownership of the load appropriately, while
maintaining the integrity of the reliability applications.
Pseudo ties (external-to-internal and internal-to-external)
• A pseudo-tied load representation is provided by the MISO so that a BA load may
be physically modeled at a bus owned by another BA.
• Load that is physically located in a Local Balancing Authority (LBA) within
the MISO but pseudo-tied to an external BA will be considered in the
external BA load calculation. The load needs to be registered for
congestion and loss charges only.
• Load that is physically located in an external BA but pseudo-tied into an
LBA with the MISO, will be considered in the LBA area load calculation
and assigned to load zones defined in the LBA
The load will be subject to the MISO Energy Market and
accounted for in the centralized dispatch
The load is only subject to transmission service arrangement it
has with these external BA and MISO is not a party to these
arrangements
7
General Policy
• The MISO’s general policy is that loads be created at all buses to which step
down transformers used to take Energy from the Transmission System and
supply the distribution system.
• Some of these loads may be serving customers of multiple MPs at the
distribution level.
• Each MP may have a separately modeled load representing its share, but it is not
a requirement.
• In cases where it is not practical to split the loads, each MP will be assigned a
static share of the load as identified by the Local Balancing Authority, which will
be used for their respective Load Zone.
Load Consolidation
• In some instances, Market Participants may wish to consolidate Loads into one
Load Zone for the loads that are on the periphery of the Local Balancing
Authority. This implementation is done in the Network Model by pseudo-tying
loads from one Local Balancing Authority to another. This implementation
redefines the Load boundary of both Local Balancing Authorities.
8
Behind the meter
• Load served by behind-the-meter generation may be excluded from the LBA
Market Load if such behind-the-meter generation is not being modeled as a
DRR-Type II. Although the load and generation can be netted from a commercial
perspective, not all of these situations allow the removal of the generators from
the Network Model. If these generators are not required in the Network Model,
there will be a simple representation of a net load that will be associated with a
Load Zone and the generator will be removed. The BPM for Network Modeling
provides specific circumstances when MISO may require that the generation and
load be included in the Network Model.
Auxiliary Load
• In the MISO, as a general rule, auxiliary loads for generation stations can be
modeled explicitly with gross generation or the auxiliary load and gross
generation can be modeled as net generation. The exception to this rule is when
the auxiliary load is served from a different Bus than the generator
interconnection Bus or there is an overriding reliability concern such as the
ability to properly model contingencies on the buses around a nuclear plant. In
that case, the auxiliary load must be explicitly modeled with gross generation.
9
DRR Type I
• Definition: A DRR-Type I is defined as any Resource hosted by an energy
consumer or Load Serving Entity that is capable of supplying a specific amount of
Energy or Contingency Reserve, at the choice of the Market Participant, to the
Energy and Operating Reserve Markets through physical load interruption.
• DRR – Type I’s may represent end-use customer programs such as industrial
interruptible load programs, controlled hot water heater programs, controlled air
conditioner programs and load reduction programs registered by Aggregators of
Retail Customers. No special modeling of a DRR-Type I is required in the
Network Model, the Network Model will continue to model a DRR-Type I
capable load as regular load.
For DRR-Type II
• Definition: A DRR-Type II is defined as any Resource hosted by an energy
consumer or Load Serving Entity that is capable of supplying a range of Energy
and/or Operating Reserve, at the choice of the Market Participant, to the Energy
and Operating Reserve Markets through behind-the-meter generation and/or
controllable load. The effective load can be physically curtailed in total or
incrementally.
• For Network Modeling purposes, both load and generation are modeled.
• The load represents the gross behind-the-meter load and the generation
represents the amount of gross load reduction that can be realized, either from
behind-the-meter generation and/or controllable load.
10
• A DRR-Type II must be at least 1 MW to be included in the Network Model.
10
• Units may be gross or net with respect to auxiliary load
• Units may be single owner or JOU
• A single owner unit or a jointly owned unit that is represented as one unit in the
MISO network model must be at least 5 MW in size.
• In the case of Jointly Owned units, each share that is explicitly represented in the
network model must have 1 MW output or higher.
• Two options for JOU units
• Units, including JOU, may be Pseudo-tied
• Into MISO
• Out of MISO
11
Units may be gross or net with respect to auxiliary load
Units may be single owner or JOU
• A single owner unit or a jointly owned unit that is represented as one unit in the
MISO network model must be at least 5 MW in size.
• In the case of Jointly Owned units, each share that is explicitly represented in the
network model must have 1 MW output or higher.
• Two options for JOU units <<discussed further>>
Behind-the-Meter Generation
• There are many units owned and operated by municipal and cooperative
systems that operate in a behind-the-meter mode.
• Load served by behind-the-meter generation may be excluded from the LBA
Market Load if such behind-the-meter generation is not being modeled as a
DRR-Type II.
• If these generators are not required in the Network Model, there will be a simple
representation of a net load that will be associated with a Load Zone and the
generator will be removed.
• ** If the true generation provides a large enough reactive power component to
have an impact on the convergence capability or solution quality of AC analysis
applications, or if the facilities behind-the-meter are actually networked with the
MISO Transmission System MISO may require that the generation and load be
included in the Network Model.
• More details pertaining to the SE solution quality measures can be found at the
12
following URL: http://www.midwestmarket.org/Docs/PerformanceMetrics.cfm,
where the MISO Metrics Interpretation Guides are posted.
Units, including JOU, may be Pseudo-tied
• Into MISO
• Out of MISO
• Within MISO
12
• In the MISO network/market model, a generating unit may be represented as
“Gross” or “Net”.
• With “Gross” Unit modeling , the Auxiliary load is explicitly modeled.
• The Generator Owner or LBA will submit “gross” MW and MVAR
values to MISO via ICCP.
• Settlement will be based on the “gross” MW values.
• With “Net” Unit modeling, the Auxiliary load is not modeled.
• The Auxiliary load must be supplied from the same bus the unit is
connected in order for this method to be used.
• The Generator Owner or LBA will submit “net” MW and MVAR
values to MISO via ICCP.
• Settlement will be based on the “net” MW values.
13
Option 1
• The unit is represented in the network model as one physical unit.
• Only one Asset Owner will submit offers for the unit.
• Input/Output data requirements for this unit are the same as for any other
unit that is participating in the MISO market.
• Asset owners handle all back-office settlements of share ratios between
themselves
Option 2
• Each JOU component of the unit is represented in the network model as
an explicit unit.
• The owner of each component (explicit unit) submits offers for that unit
• All input data required for units participating in the market must be made
available to MISO for each JOU component
• A firm transmission path must be available for each unit that is pseudotied into the MISO market
• Each JOU component that is not participating in the MISO market will be
pseudo-tied out.
14
15
Pseudo-Tied Into MISO
• A unit that is connected directly to an External transmission system, but is telemetered
into MISO
• Requires Transmission Service from the External Transmission Owner.
• This unit will be dispatched by the MISO
• This unit will be included in the MISO AGC function or ACE calculation
Pseudo-Tied Out of MISO
• A unit that is connected directly to the MISO transmission system, but is telemetered
into an External BA
• Requires Transmission Service from MISO.
• This unit will not be dispatched by the MISO
• This unit will be included in the External Balancing Authority AGC function and
ACE calculation of the
16
The criterion for Intermittent Resource Registration:
Prior to March 1, 2013, a Generation Resource can be considered an Intermittent
Resource if it is incapable of being dispatched or following Setpoint Instructions.
On or after March 1, 2013, a Generation Resource can be considered an
Intermittent Resource if such Generation Resource is incapable of following
Setpoint Instructions and:
• The Commercial Operation Date as set forth in the Resource’s Generator
Interconnection Agreement or equivalent agreement is prior to April 1,
2005;
(or)
• Any of the following apply to the Capacity of the Generation Resource in
an amount, either separately or combined, that equals the total Capacity
of the Generation Resource:
• The Generation Resource has been interconnected to the Facilities
operated by the Transmission provider through Network Resource
Interconnection Service;
• The Generation Resource has been designated as a Network
Resource under Module B of the Tariff; or
• The Energy produced by the Generation Resource is subject to an
agreement for Long-Term Firm Point-to-Point Transmission
Service.
17
Note: Change is based upon the following with references for further detail…
Dispatchable Intermittent Resource (DIR) Proposal
• Utilize Forecast Maximum Limit to allow full market participation for
wind (and other like resources) as sub-set of Generation Resources
• DIR registration required for Resources with “Intermittent” Market
Registration
• See next slide for complete description
• DIR and Generation Resources Receive Identical Settlements
Treatment
• RSG Identical to Generation for *positive differences*
between DA schedules and RT capability
• Same setpoint tolerance as generation resources
• All Resources with “Intermittent” Market Registration subject to RSG
for *positive and negative differences* between DA schedules and
RT capability
• This provision supersedes similar language filed with RSG
redesign, and filed as part of this DIR Tariff filing
• Filed as part of this DIR Tariff filing
Final Tariff Sheets Posted on MISO public web
• Module A: Define DIR and Forecast Max. Limit
• Module C: Offer details, Settlements details, Registration (Corrected
Registration Requirement language)
• Module E: Capacity details
• Attachment X: Control Equipment
Registration Requirement: More Detail
• Resources that the Registration Requirement Applies To
• Resources that are currently registered with market
registration type “Intermittent”, that do not have 100% NRIS
and/or 100% Long-Term Firm Transmission Service, must
register as DIR
• Procuring long-term firm transmission service after today
DOES allow for continued registration as type “Intermittent”
• Resources that receive a permanent waiver from the Registration
Requirement
• Resources currently registered with market registration type
“Intermittent”, that were in operation before April 1, 2005
• Two-Year Transition Period
• Resources subject to the registration requirement have a twoyear transition period before DIR registration is required
• All resources with “Intermittent” Registration type will be subject to
RSG provision, regardless of transmission service or waiver status
17
• Resources not subject to registration requirement are encouraged to
register as DIR
Market Subcommittee Materials
• Located on the MISO public web
(https://www.midwestiso.org/StakeholderCenter/CommitteesWorkGr
oupsTaskForces/MSC/Pages/)
• 20100831 MSC Item 13b DIR Proposal
• 20101207 MSC Item 07 Wind Integration Workplan
17
• Each generator that is represented in the network model and is a price-setter in the
MISO market must have a breaker associated with it.
• ICCP Telemetry on the unit breaker must accurately represent when the unit is ON or
OFF
• The maximum output for a unit must be ≥ 5MW for the unit to be explicitly represented
in the network model and be a price-setter in the market.
• Units that are between 1 MW and 5 MW may be modeled in the Commercial Model for
settlements purposes only but will not be explicitly modeled in the Network Model.
• Units below 1 MW are not modeled in either the Network or Commercial Model.
• Accurate unit representation prevents false setpoints or dispatch targets being sent to
the Local Balancing Authority.
18
• All transmission facilities including transmission lines, transformers, phase shifters and
shunt reactive power devices must be modeled in the MISO Network Model.
• Transmission level facilities are typically operated at 100 kV and above.
• Any requests for monitoring facilities at or below 69 kV will be reviewed for justification
and must have telemetered measurements available to the MISO through ICCP.
19
Type 1:
• Tie lines in the MISO EMS network model that are metered (i.e., Metered
tie lines that have one-to-one relationship with tie lines represented in the
MISO EMS network model)
• Each LBA is required to provide individual real-time metering data, via
ICCP, for each of these tie lines
Type 2:
• Tie lines in the MISO EMS network model that are not metered / not
individually metered
• Option A: Each LBA is required to provide manually entered value
(agreed upon between the two entities on each end of the ties), via
ICCP, for each individual tie line
• Option B: Each LBA is required to provide one measurement that is
the sum of a list of tie lines modeled in the network model
Type 3:
• Tie lines NOT in MISO EMS network model. There are two categories
belonging to Type 3:
• Tie lines that have real-time metering, but are located in the lower
kV system that is not represented in the MISO EMS network model
• Un-metered tie lines that are not represented in the MISO EMS
network model
• Each LBA is required to provide ONE value that is the total of Type 3 tie
lines (i.e., for both metered & un-metered tie lines that belong to type 3).
Important Note
Proper tie Line modeling and verification are important to ensure correct definition of
the Balancing Authority metered boundary for the following reasons:
20
1. BA/LBA area ICCP load is the primary input data to the Short Term Load
Forecast (STLF) application. The STLF application produces the 5-minute
load forecasts used for real-time generation dispatch in the Real-Time
market. The accuracy of the BA/LBA area ICCP load depends on how well
the BA/LBA metered boundary is defined.
2. Also, BA/LBA area ICCP load is key input to the Mid-Term Load Forecast
(MTLF) application that produces the hourly load forecast used for unit
commitment in the Day Ahead Market
3. The BA/LBA area ICCP load is key input to the State Estimator application,
a major tool used for monitoring the transmission system reliability.
4. Proper tie line monitoring is important to ensure proper calculation of ACE
in the AGC application
20
Market Participant
• The MP is the entity that is financially obligated to the MISO for Market
Settlements.
• The MP must have associations with at least one Asset Owner.
Asset Owners
• Asset Owners are commonly referred to as LSEs or Generation Owners but an
Asset Owner can own any combination of generation and load.
• Not all Asset Owners must have physical Assets of load and generation.
• Includes entities associated with Bilateral Transactions and FTRs
• All Energy and Operating Reserve Markets transactions for generation, load,
FTRs and bilateral schedules are settled to the level of the Asset Owners and
then invoiced to the MP.
• Must be represented by one MP, but a MP may have multiple Asset Owners.
• Not required for Hubs, Interfaces, or Loop Nodes
• MP-to-AO relationship allows for full flexibility for a MP to manage its users’
access and to separate internal business units or provide MP services for
multiple entities with separate settlements for each
Assets
• An asset must be represented by an Asset Owner
• Generation (including Load-modifying resources) and Load.
• Directly related to CPNodes.
• Generation Assets, 7 specific types.
• Single Generation Assets
21
• Behind-the-Meter Generation
• Jointly-Owned Unit Data
• Pumped Storage Units
• Aggregate Generation Assets (Combined Cycle and Cross Compound)
• External Asynchronous Resources
• External Pseudo-Tie Generation
• Capacity Resources, 2 specific types:
• Demand Response Resources (DRR) – Type I (e.g. industrial interruptible
load & registered retail load reduction)
• Demand Response Resources (DRR) – Type II (behind the meter
generation capable of receiving electronic dispatch)
• Load Assets, 3 specific types:
• Load Zones
• External Pseudo-Tie Loads
• Non-Conforming Loads
CPNodes
• Key points in the Commercial Model.
• Aggregate of EPNodes.
• CPNodes are grouped into 12 specific types:
• Generation Resource
• DRR-Type I
• DRR-Type II
• Combined Cycle or Cross Compound Collection
• Stored Energy Resource (SER)
• Load Zone
• External Interface
• Hub (ARR Zones are defined as a Hub Type)
• External Asynchronous Resource (EAR)
• External Pseudo-Tied Generator (PSG)
• External Pseudo-Tied Load (PSL)
• Loop Node
EPNodes
• An Elemental Pricing Node is a Single Bus Node where Location Marginal Price is
Calculated.
• Represent physical elements in the Network Model.
• May have a one-to-one, one-to-many, or many-to-many relationships with
CPNodes depending on the CPNode Type.
• As of today the following EPNode types are supported in the MISO Markets:
• Generation
• Load
• Other [Associated with the Non Injection Non Withdrawal (NINW) nodes
in the Network Model]
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CPNode Naming Convention
• Started by NERC Registered BA acronym
• Followed by a “.”, and then with the rest of the characters
• No special characters, except the dot “.” and the underscore “_”.
• Total length cannot exceed 14 characters.
• Example: CIN.GIBSON_4 or CIN.GIBSON1
EPNode Name Format (derived from Network Model)
EPNode names are established automatically based on LBA, station name,
and equipment ID. The three types of EPNodes identified above are defined
by a standard Network Model naming convention. Each has a four-part
unique name. The convention for each is described as follows:
• Generation EPNodes – The letter “U” concatenated with the EMS LBA
name, the EMS station name, and the EMS Unit ID.
•
Example: U LGEE GHENT GHENT_2
• Load EPNodes – The letter “L” concatenated with the EMS LBA name, the
EMS station name, and the EMS Load ID.
•
Example: L LGEE GHENT GHENT
• NINW EPNodes – The letter “N” concatenated with the EMS LBA name,
the EMS station name, and the node ID.
•
Example: N LGEE SMITH OMU
22
• NINW EPNodes have a one-to-one relationship to a transmission node that does not
have generation or load directly connected.
• A Locational Marginal Price (LMP) is calculated at each EPNode. Any Node in the
Network Model can have an LMP.
• NINW EPNodes are created at select locations and may be used in the representation of
Hubs, External Interfaces, below threshold generation, and behind-the-meter loads.
23
24
25
26
• When a generating unit is represented as behind the meter generator in the network
model, a non-commercial EPNode is set up for such a unit in the commercial model.
• No CPNode will be created for the behind the meter generator.
• The settled MW is the net of the load and the behind the meter generator output as
illustrated below.
• Network Model maintains Gen and Load while Commercial model reflects aggregate of
NINW as a single load point.
Important Notes:
• In the Market, no specific LMP is produced for a behind the meter unit. It also
can not be committed and does not receive RSG Make-Whole Payments.
• If the behind the meter unit is large enough to cause a net injection at the Load
Zone on a routine basis, it can not be adequately represented in the Day-Ahead
Market to avoid RSG. (No ability to submit negative demand bids on a Load
Zone)
• Behind the meter generator has the option to register as a DRR Type 2. The DRR
Type 2 will have a CPNode in the commercial model and MISO will produce an
LMP and transmit generation Setpoints / Dispatch Targets for the resource.
27
Option 1
• The jointly owned unit will be modeled only as one generator in the
commercial model.
• Only the registered party will receive a settlement statement; the relevant
parties will settle their JOU shares among themselves.
• There will be one corresponding unit in the commercial model, with one
CPNode.
• Only one Asset Owner will submit offers for the unit.
• Input/Output data requirements for this unit are the same as for any other
unit that is participating in the MISO market.
Option 2
• The jointly owned unit will be split into multiple distinct units in the
commercial model.
• Each party has its own EPNode and CPNode representing it’s share.
• All parties participate in the market separately using their own CPNodes.
• Coordination of ramp rates, outages, limits and other offer parameters will
still be required by the participants.
• Each party will receive separate settlement statement for their JOU share.
Comments
1. The CPNodes under either option can be utilized as designated network
28
resources for the ARR allocation process
2. The LMPs should be very close between Options 1 and 2
3. Each participant would be considered for revenue sufficiency and the other
make whole payments in the Energy Market or ASM.
28
DRR Type I
• DRR Type-I is a resource hosted by an energy consumer or LSE that is capable of
supplying a specific quantity of Energy to the market through physical load
interruption.
• DRR Type-I are committable but not dispatchable.
• DRR Type-I will be modeled with two CPNodes.
• One CPNode represents the resource offering DRR Type-I (collection type DRR
Type-I)
• The other CPNode represents the load (Load Zone CPNode) associated with this
resource.
• DRR Type-I can supply either energy or contingency reserve but not both of
them at the same time.
• The resources are required to offer for contingency reserves, and the market will
decide whether to commit them for energy or for reserves.
DRR-Type II
• DRR Type-II is a Resource hosted by an energy consumer or load serving entity
that is capable of supplying Energy to the market through behind-the-meter
generation or controllable load.
• Demand Response Resource Type-II are committable and dispatchable.
• DRR Type-II will be modeled like a generator. It will include a reference Load
Zone CPNode. This Load Zone CPNode exclusively represents the Load EPNode
29
that is reduced by the deployment of DRR.
• DRR Type-II can provide Energy, Regulation and Contingency Reserves.
29
• EPNodes and CPNodes have an effective date and termination date to reflect Network
Model and Commercial Model changes
• PNodes in DART correspond to current EMS Network and Commercial Model
• PNodes in FTR correspond to future Network and Commercial Model. After the future
model is built, PNodes will be updated accordingly.
30
Important Note
• MISO offers provisional processes in the event of generator ownership
change if MPs are not able to establish a firm transaction date and still
want this change to reflect in the commercial model.
• Emergency corrections necessary to ensure reliable operation of the
MISO Transmission System and Market Operations, will be made and
MISO will apply the model changes between the normal quarterly updates
after performing all steps for validation and testing.
31
Future Facilities are included in the network model
• MISO updates its EMS model on a quarterly basis.
• All known and confirmed transmission system changes for the next
3-4 months must be submitted to MISO for inclusion in the
“current” model update.
• Future equipment modeling is achieved through double modeling
techniques and use of the Outage Scheduler.
• To ensure proper representation of the future equipment in the
network model, the equipment limits, breaker configuration and
breaker status information must be provided.
• The Network and Commercial Model are posted quarterly for
review by TO’s, BA’s and MP’s.
• Emergency corrections necessary to ensure reliable operation of
the MISO Transmission System and Market Operations, will be
made and MISO will apply the model changes between the normal
quarterly updates after performing all steps for validation and
testing.
Double Modeling
• It is important to note that all monthly and annual FTR models are derived
from the Network Model by adding known future equipment to the Network
Model that is used for real-time operations. The resulting modified
32
Network Model is converted to a bus-branch model in the PTI PSS/E format
and used as the FTR model; this is often referred to as “double modeling”.
• The main difference between the Network Model and bus-branch model
formats is that circuit breakers are not represented in the FTR model.
• The Outage Scheduler is used to set those changes that are not effective
immediately at the loading time of the Network Model to inactive until such
time as the equipment is switched in.
32
• Example: Assume Submission deadline Dec 15th
• EMS model (Network Model) should have all the changes effective between
March 1st and May 31st at 23:59:59 Hrs
• Even though model isn't effective until June 1st.
• MISO needs to include all the changes until July 1st into the EMS model
to accommodate schedule changes in the in-service dates.
33
Impact on FTR Seasonal Model Builds
• FTR Seasonal Models – 5 FTR models are built in the quarter for March, 4 in June, 3 in
September, 2 in December – include the changes effective from:
• Base FTR Model will be same as EMS model
• The FTR model changes for the summer FTR model should include all known,
approved and budgeted future equipment that will be in service by June 1st
• All equipment in service on June 1st will be in the model
• The FTR model changes for the fall FTR model should include all known,
approved and budgeted future equipment that will be in service by Sept 1st
• All equipment in service on Sept 1st will be in the model
• The FTR model changes for the winter FTR model should include all known,
approved and budgeted future equipment that will be in service by Dec 1st
• All equipment in service on Dec 1st will be in the model
• The FTR model changes for the Spring FTR model should include all known,
approved and budgeted future equipment that will be in service by March 1st
• All equipment in service on March 1st will be in the model
34
35
36
• Areva Netmodel Save Case
• if the submitter’s EMS vendor is Areva then MISO would prefer to receive save
cases for Network and SCADA models
• Custom Database Formats (PJM)
• EMS model description in a predefined MS-Access database structure
• PSS/E format (IDV or python files) with Single Lines
• describing incremental changes
• CIM (NYISO and ONT)
• Model exchange in Common Informational Model format
• Emails
• describing changes and attached Single line diagrams
37
The policy-driven quarterly update schedule. These dates are general guidelines and may
vary. Consult the annual model release and update calendar published on the MISO public
web site.
Note: Review cutoff dates may be adjusted due to weekends, holidays, or other
circumstances allowing additional time.
38
The following processes and methods currently exist for reviewing MISO Network,
Commercial, and FTR models:
On-site Model Review:
• Transmission Owners and MPs who have a Non-Disclosure Agreement
(NDA) on file are able to perform on-site review of the Network Model and
the SE solution by visiting MISO control room in Carmel or St. Paul.
Citrix System:
• Transmission Owners and MPs who have an NDA on file are able to
perform off-site review of the Network Model and the SE solution via
remote terminals installed at their sites by MISO. The NDA is required for
the off-site review of the Network Model since the SE solution represents
Real-Time system data. The Citrix method provides access to the
following:
• SCADA Displays
• RTNET Displays
• RTCA Displays
Daily Posted Model:
• TOs may Perform off-site review of the Network Model and the SE
solution by downloading the model posted daily Extranet.
• The NDA is required for this off-site review of the Network Model since the
39
SE solution that is posted with the Network Model represents Real-Time
system data.
14-day Old Posted Models:
• All MPs have access to the 14-day old Network Models that are posted on
the MISO Extranet.*
Reviewing Commercial Model Data:
• Whenever the Network Model is updated, the Commercial Model is updated
to be consistent with the Network Model. The updated Commercial Model
changes are posted for review by MPs at the same MISO Extranet site
listed above.*
Reviewing FTR Models:
• FTR models are available on the MISO Market Portal under the FTR tab for
the corresponding allocation or auction.
* Note: Access to the Extranet may require a special NDA. Contact Client Relations
for further clarification.
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Static Data (registration)
Network model
• Network Model Static Data consists of mathematical representations of
each power system component.
• MISO Network Model Data Modification Web Tool document describes
static data requirements
Commercial Model
• Static data consists of asset parameters provided during the registration
process.
• The Network and Commercial Modeling BPM defines the required
parameters. Examples include:
• Dispatch Status (available for update on an hourly basis)
• Min/Max Outputs and Limits
• Unit Type and Fuel type
• Qualification Flags
• CPNode names and MP/AO/MDMA/SA assignments
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Dynamic Data (telemetry)
Network Model
• MISO ICCP Data Exchange Specification describes the data,
frequency requirements, and naming conventions for data
exchanged via ICCP to and from MISO.
• telemetered data supplied to MISO by the Transmission Owners
and the MPs is mapped to the static model components
• The telemetered values used to support Real-Time analyses are:
• Switching Device Status (Open/Close)
• Line and Transformer Flow (MW and MVAR)
• Circuit Breaker Flows (MW and MVAR)
• Net or Gross Generation (MW and MVAR)
• Generation Auxiliaries (MW and MVAR)
• Synchronous Condenser and Static VAR Compensator
(MW and MVAR)
• Load (MW and MVAR)
• Bus Voltage Magnitudes (kV)
• Transformer and phase shifter tap positions
• The SE can use both paired and unpaired real and reactive power
measurements.
• The more telemetry that is available to the SE, the more likely the
SE will return a more accurate solution.
• The SE will make use of forecast and default values if Real-Time
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data is unavailable.
• Limits for transmission lines, loads, transformers, and shunts
supplied by the Transmission Owners are assigned to each
measurement.
• MISO operators are primarily concerned with three ratings for each
piece of equipment.
• Normal ratings
• Emergency ratings
• Interconnection Reliability Operating Limit ratings
• Telemetry for the following resources is required to participate in the
Energy and Operating Reserves Markets
•
Generators
•
Stored Energy Resources
•
DRR Type II
Commercial Model
• Settlement Meter Data – Revenue Quality Meter Data is provided by
the registered Meter Data Management (MDMA) Agent for
applicable CPNodes in the Commercial Model. Further information is
covered by Market Settlements training.
• Commercial Model has no special telemetry data requirements
beyond those addressed by the ICCP Data Exchange Specification.
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This is a high-level snapshot of an ICCP setup and test. Actual ICCP connectivity projects
may have technical and business constraints not listed here.
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No additional notes. This is a summary of important points for this level of training; this
information is not intended to replace the BPM. It is every Market participant’s
responsibility to understand fully the Business Practice Manuals and relevant sections of
the MISO Tariff.
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No additional notes. This is a summary of important points for this level of training; this
information is not intended to replace the BPM. It is every Market participant’s
responsibility to understand fully the Business Practice Manuals and relevant sections of
the MISO Tariff.
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All materials listed are available via the MISO public web site. Extranet access is authorized
through the Client Relations department and may require a Universal Non-Disclosure
Agreement (UNDA) be executed prior to access.
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