Reliability Standard MOD-032-1

MOD-032-1 — Data for Power System Modeling and Analysis

A. Introduction
1.

Title: Data for Power System Modeling and Analysis

2.

Number:

3.

Purpose: To establish consistent modeling data requirements and reporting
procedures for development of planning horizon cases necessary to support analysis
of the reliability of the interconnected transmission system.

4.

Applicability:

MOD-032-1

4.1. Functional Entities:
4.1.1 Balancing Authority
4.1.2 Generator Owner
4.1.3 Load Serving Entity
4.1.4 Planning Authority and Planning Coordinator (hereafter collectively
referred to as “Planning Coordinator”)
This proposed standard combines “Planning Authority” with “Planning
Coordinator” in the list of applicable functional entities. The NERC
Functional Model lists “Planning Coordinator” while the registration
criteria list “Planning Authority,” and they are not yet synchronized. Until
that occurs, the proposed standard applies to both Planning Authority
and Planning Coordinator.
4.1.5 Resource Planner
4.1.6 Transmission Owner
4.1.7 Transmission Planner
4.1.8 Transmission Service Provider
5.

Effective Date:
MOD-032-1, Requirement R1 shall become effective on the first day of the first
calendar quarter that is 12 months after the date that the standard is approved by an
applicable governmental authority or as otherwise provided for in a jurisdiction where
approval by an applicable governmental authority is required for a standard to go into
effect. Where approval by an applicable governmental authority is not required,
MOD-032-1, Requirement R1 shall become effective on the first day of the first
calendar quarter that is 12 months after the date the standard is adopted by the NERC
Board of Trustees or as otherwise provided for in that jurisdiction.
MOD-032-1, Requirements R2, R3, and R4 shall become effective on the first day of
the first calendar quarter that is 24 months after the date that the standard is
approved by an applicable governmental authority or as otherwise provided for in a
jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority
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MOD-032-1 — Data for Power System Modeling and Analysis

is not required, MOD-032-1, Requirements R2, R3, and R4 shall become effective on
the first day of the first calendar quarter that is 24 months after the date the standard
is adopted by the NERC Board of Trustees or as otherwise provided for in that
jurisdiction.
6.

Background:
MOD-032-1 exists in conjunction with MOD-033-1, both of which are related to
system-level modeling and validation. Reliability Standard MOD-032-1 is a
consolidation and replacement of existing MOD-010-0, MOD-011-0, MOD-012-0,
MOD-013-1, MOD-014-0, and MOD-015-0.1, and it requires data submission by
applicable data owners to their respective Transmission Planners and Planning
Coordinators to support the Interconnection-wide case building process in their
Interconnection. Reliability Standard MOD-033-1 is a new standard, and it requires
each Planning Coordinator to implement a documented process to perform model
validation within its planning area.
The transition and focus of responsibility upon the Planning Coordinator function in
both standards are driven by several recommendations and FERC directives from FERC
Order No. 693, which are discussed in greater detail in the rationale sections of the
standards. One of the most recent and significant set of recommendations came from
the NERC Planning Committee’s System Analysis and Modeling Subcommittee (SAMS).
SAMS proposed several improvements to the modeling data standards, to include
consolidation of the standards (the SAMS whitepaper is available from the December
2012 NERC Planning Committee’s agenda package, item 3.4, beginning on page 99,
here:
http://www.nerc.com/comm/PC/Agendas%20Highlights%20and%20Minutes%20DL/2
012/2012_Dec_PC%20Agenda.pdf).

B. Requirements and Measures
R1.

Each Planning Coordinator and each of its Transmission Planners shall jointly develop
steady-state, dynamics, and short circuit modeling data requirements and reporting
procedures for the Planning Coordinator’s planning area that include: [Violation Risk
Factor: Lower] [Time Horizon: Long-term Planning]
1.1. The data listed in Attachment 1.
1.2. Specifications of the following items consistent with procedures for building the
Interconnection-wide case(s):
1.2.1. Data format;
1.2.2. Level of detail to which equipment shall be modeled;
1.2.3. Case types or scenarios to be modeled; and
1.2.4. A schedule for submission of data at least once every 13 calendar
months.

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MOD-032-1 — Data for Power System Modeling and Analysis

1.3. Specifications for distribution or posting of the data requirements and reporting
procedures so that they are available to those entities responsible for providing
the data.
M1. Each Planning Coordinator and Transmission Planner shall provide evidence that it has

jointly developed the required modeling data requirements and reporting procedures
specified in Requirement R1.
R2.

Each Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner,
Transmission Owner, and Transmission Service Provider shall provide steady-state,
dynamics, and short circuit modeling data to its Transmission Planner(s) and Planning
Coordinator(s) according to the data requirements and reporting procedures
developed by its Planning Coordinator and Transmission Planner in Requirement R1.
For data that has not changed since the last submission, a written confirmation that
the data has not changed is sufficient. [Violation Risk Factor: Medium] [Time Horizon:
Long-term Planning]

M2. Each registered entity identified in Requirement R2 shall provide evidence, such as

email records or postal receipts showing recipient and date, that it has submitted the
required modeling data to its Transmission Planner(s) and Planning Coordinator(s); or
written confirmation that the data has not changed.
R3.

Upon receipt of written notification from its Planning Coordinator or Transmission
Planner regarding technical concerns with the data submitted under Requirement R2,
including the technical basis or reason for the technical concerns, each notified
Balancing Authority, Generator Owner, Load Serving Entity, Resource Planner,
Transmission Owner, or Transmission Service Provider shall respond to the notifying
Planning Coordinator or Transmission Planner as follows: [Violation Risk Factor:
Lower] [Time Horizon: Long-term Planning]
3.1. Provide either updated data or an explanation with a technical basis for
maintaining the current data;
3.2. Provide the response within 90 calendar days of receipt, unless a longer time
period is agreed upon by the notifying Planning Coordinator or Transmission
Planner.

M3. Each registered entity identified in Requirement R3 that has received written

notification from its Planning Coordinator or Transmission Planner regarding technical
concerns with the data submitted under Requirement R2 shall provide evidence, such
as email records or postal receipts showing recipient and date, that it has provided
either updated data or an explanation with a technical basis for maintaining the
current data to its Planning Coordinator or Transmission Planner within 90 calendar
days of receipt (or within the longer time period agreed upon by the notifying
Planning Coordinator or Transmission Planner), or a statement that it has not received
written notification regarding technical concerns with the data submitted.

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MOD-032-1 — Data for Power System Modeling and Analysis

R4.

Each Planning Coordinator shall make available models for its planning area reflecting
data provided to it under Requirement R2 to the Electric Reliability Organization (ERO)
or its designee to support creation of the Interconnection-wide case(s) that includes
the Planning Coordinator’s planning area. [Violation Risk Factor: Medium] [Time
Horizon: Long-term Planning]

M4. Each Planning Coordinator shall provide evidence, such as email records or postal

receipts showing recipient and date, that it has submitted models for its planning area
reflecting data provided to it under Requirement R2 when requested by the ERO or its
designee.

Page 4 of 19

MOD-032-1 — Data for Power System Modeling and Analysis

C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Enforcement Authority
“Compliance Enforcement Authority” means NERC or the Regional Entity in their
respective roles of monitoring and enforcing compliance with the NERC
Reliability Standards.
1.2. Evidence Retention
The following evidence retention periods identify the period of time an entity is
required to retain specific evidence to demonstrate compliance. For instances
where the evidence retention period specified below is shorter than the time
since the last audit, the Compliance Enforcement Authority may ask an entity to
provide other evidence to show that it was compliant for the full time period
since the last audit.
The applicable entity shall keep data or evidence to show compliance with
Requirements R1 through R4, and Measures M1 through M4, since the last audit,
unless directed by its Compliance Enforcement Authority to retain specific
evidence for a longer period of time as part of an investigation.
If an applicable entity is found non-compliant, it shall keep information related
to the non-compliance until mitigation is complete and approved, or for the time
specified above, whichever is longer.
The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.
1.3. Compliance Monitoring and Assessment Processes:
Refer to the NERC Rules of Procedure for a list of compliance monitoring and
assessment processes.
1.4. Additional Compliance Information
None

Page 5 of 19

Table of Compliance Elements
R#

R1

Time Horizon

Long-term
Planning

VRF

Lower

Violation Severity Levels
Lower VSL

Moderate VSL

High VSL

Severe VSL

The Planning
Coordinator and
Transmission
Planner(s) developed
steady-state,
dynamics, and short
circuit modeling data
requirements and
reporting procedures,
but failed to include
less than or equal to
25% of the required
components specified
in Requirement R1.

The Planning
Coordinator and
Transmission
Planner(s) developed
steady-state,
dynamics, and short
circuit modeling data
requirements and
reporting procedures,
but failed to include
greater than 25% but
less than or equal to
50% of the required
components specified
in Requirement R1.

The Planning
Coordinator and
Transmission
Planner(s) developed
steady-state,
dynamics, and short
circuit modeling data
requirements and
reporting procedures,
but failed to include
greater than 50% but
less than or equal to
75% of the required
components specified
in Requirement R1.

The Planning and
Transmission
Planner(s) Coordinator
did not develop any
steady-state,
dynamics, and short
circuit modeling data
requirements and
reporting procedures
required by
Requirement R1;

Page 6 of 19

OR
The Planning
Coordinator and
Transmission
Planner(s) developed
steady-state,
dynamics, and short
circuit modeling data
requirements and
reporting procedures,
but failed to include
greater than 75% of
the required
components specified

in Requirement R1.
R2

Long-term
Planning

Medium The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service
Provider provided
steady-state,
dynamics, and short
circuit modeling data
to its Transmission
Planner(s) and
Planning
Coordinator(s), but
failed to provide less
than or equal to 25%
of the required data
specified in
Attachment 1;
OR
The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service
Provider provided

The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service
Provider provided
steady-state,
dynamics, and short
circuit modeling data
to its Transmission
Planner(s) and
Planning
Coordinator(s), but
failed to provide
greater than 25% but
less than or equal to
50% of the required
data specified in
Attachment 1;

The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service
Provider provided
steady-state,
dynamics, and short
circuit modeling data
to its Transmission
Planner(s) and
Planning
Coordinator(s), but
failed to provide
greater than 50% but
less than or equal to
75% of the required
data specified in
Attachment 1;

OR

OR

The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service

The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service
Page 7 of 19

The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service
Provider did not
provide any steadystate, dynamics, and
short circuit modeling
data to its
Transmission
Planner(s) and
Planning
Coordinator(s);
OR
The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service
Provider provided
steady-state,
dynamics, and short
circuit modeling data
to its Transmission

steady-state,
dynamics, and short
circuit modeling data
to its Transmission
Planner(s) and
Planning
Coordinator(s), but
less than or equal to
25% of the required
data failed to meet
data format,
shareability, level of
detail, or case type
specifications;
OR
The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service
Provider failed to
provide steady-state,
dynamics, and short
circuit modeling data
to its Transmission
Planner(s) and
Planning
Coordinator(s) within
the schedule specified

Provider provided
steady-state,
dynamics, and short
circuit modeling data
to its Transmission
Planner(s) and
Planning
Coordinator(s), but
greater than 25% but
less than or equal to
50% of the required
data failed to meet
data format,
shareability, level of
detail, or case type
specifications;

Provider provided
steady-state,
dynamics, and short
circuit modeling data
to its Transmission
Planner(s) and
Planning
Coordinator(s), but
greater than 50% but
less than or equal to
75% of the required
data failed to meet
data format,
shareability, level of
detail, or case type
specifications;

OR

OR

The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service
Provider failed to
provide steady-state,
dynamics, and short
circuit modeling data
to its Transmission
Planner(s) and
Planning

The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service
Provider failed to
provide steady-state,
dynamics, and short
circuit modeling data
to its Transmission
Planner(s) and
Planning
Page 8 of 19

Planner(s) and
Planning
Coordinator(s), but
failed to provide
greater than 75% of
the required data
specified in
Attachment 1;
OR
The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service
Provider provided
steady-state,
dynamics, and short
circuit modeling data
to its Transmission
Planner(s) and
Planning
Coordinator(s), but
greater than 75% of
the required data
failed to meet data
format, shareability,
level of detail, or case
type specifications;

R3

Long-term
Planning

Lower

by the data
requirements and
reporting procedures
but did provide the
data in less than or
equal to 15 calendar
days after the
specified date.

Coordinator(s) within
the schedule specified
by the data
requirements and
reporting procedures
but did provide the
data in greater than 15
but less than or equal
to 30 calendar days
after the specified
date.

Coordinator(s) within
the schedule specified
by the data
requirements and
reporting procedures
but did provide the
data in greater than 30
but less than or equal
to 45 calendar days
after the specified
date.

OR

The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service

The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service

The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service

The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, Transmission
Owner, or
Transmission Service

Page 9 of 19

The Balancing
Authority, Generator
Owner, Load Serving
Entity, Resource
Planner, or
Transmission Service
Provider failed to
provide steady-state,
dynamics, and short
circuit modeling data
to its Transmission
Planner(s) and
Planning
Coordinator(s) within
the schedule specified
by the data
requirements and
reporting procedures
but did provide the
data in greater than 45
calendar days after the
specified date.

Provider failed to
provide a written
response to its
Transmission
Planner(s) or Planning
Coordinator(s)
according to the
specifications of
Requirement R4 within
90 calendar days (or
within a longer period
agreed upon by the
notifying Planning
Coordinator or
Transmission Planner),
but did provide the
response within 105
calendar days (or
within 15 calendar
days after the longer
period agreed upon by
the notifying Planning
Coordinator or
Transmission Planner).

Provider failed to
provide a written
response to its
Transmission
Planner(s) or Planning
Coordinator(s)
according to the
specifications of
Requirement R4 within
90 calendar days (or
within a longer period
agreed upon by the
notifying Planning
Coordinator or
Transmission Planner),
but did provide the
response within
greater than 105
calendar days but less
than or equal to 120
calendar days (or
within greater than 15
calendar days but less
than or equal to 30
calendar days after the
longer period agreed
upon by the notifying
Planning Coordinator
or Transmission
Planner).

Provider failed to
provide a written
response to its
Transmission
Planner(s) or Planning
Coordinator(s)
according to the
specifications of
Requirement R4 within
90 calendar days (or
within a longer period
agreed upon by the
notifying Planning
Coordinator or
Transmission Planner),
but did provide the
response within
greater than 120
calendar days but less
than or equal to 135
calendar days (or
within greater than 30
calendar days but less
than or equal to 45
calendar days after the
longer period agreed
upon by the notifying
Planning Coordinator
or Transmission
Planner).

Page 10 of 19

Provider failed to
provide a written
response to its
Transmission
Planner(s) or Planning
Coordinator(s)
according to the
specifications of
Requirement R4 within
135 calendar days (or
within a longer period
agreed upon by the
notifying Planning
Coordinator or
Transmission Planner).

R4

Long-term
Planning

Medium The Planning
Coordinator made
available the required
data to the ERO or its
designee but failed to
provide less than or
equal to 25% of the
required data in the
format specified by
the ERO or its
designee.

The Planning
Coordinator made
available the required
data to the ERO or its
designee but failed to
provide greater than
25% but less than or
equal to 50% of the
required data in the
format specified by
the ERO or its
designee.

The Planning
Coordinator made
available the required
data to the ERO or its
designee but failed to
provide greater than
50% but less than or
equal to 75% of the
required data in the
format specified by
the ERO or its
designee.

D. Regional Variances
None.
E. Interpretations
None.
F. Associated Documents
None.

Page 11 of 19

The Planning
Coordinator made
available the required
data to the ERO or its
designee but failed to
provide greater than
75% of the required
data in the format
specified by the ERO
or its designee.

MOD-032-01 – ATTACHMENT 1:
Data Reporting Requirements
The table, below, indicates the information that is required to effectively model the interconnected transmission system for the NearTerm Transmission Planning Horizon and Long-Term Transmission Planning Horizon. Data must be shareable on an interconnectionwide basis to support use in the Interconnection-wide cases. A Planning Coordinator may specify additional information that
includes specific information required for each item in the table below. Each functional entity1 responsible for reporting the
respective data in the table is identified by brackets “[functional entity]” adjacent to and following each data item. The data reported
shall be as identified by the bus number, name, and/or identifier that is assigned in conjunction with the PC, TO, or TP.
steady-state
(Items marked with an asterisk indicate data that vary
with system operating state or conditions. Those items
may have different data provided for different modeling
scenarios)

dynamics
(If a user-written model(s) is submitted
in place of a generic or library model, it
must include the characteristics of the
model, including block diagrams, values
and names for all model parameters,
and a list of all state variables)

1.

1.

2.

3.

Each bus [TO]
a. nominal voltage
b. area, zone and owner
Aggregate Demand2 [LSE]
a. real and reactive power*
b. in-service status*
Generating Units3 [GO, RP (for future planned resources only)]
a. real power capabilities - gross maximum and minimum values
b. reactive power capabilities - maximum and minimum values at

2.
3.
4.
5.

Generator [GO, RP (for future planned
resources only)]
Excitation System [GO, RP(for future planned
resources only)]
Governor [GO, RP(for future planned resources
only)]
Power System Stabilizer [GO, RP(for future
planned resources only)]
Demand [LSE]

short circuit

1.

Provide for all applicable elements in
column “steady-state” [GO, RP, TO]
a. Positive Sequence Data
b. Negative Sequence Data
c. Zero Sequence Data
2. Mutual Line Impedance Data [TO]
3. Other information requested by the
Planning Coordinator or Transmission
Planner necessary for modeling

1

For purposes of this attachment, the functional entity references are represented by abbreviations as follows: Balancing Authority (BA), Generator Owner (GO), Load Serving Entity (LSE), Planning
Coordinator (PC), Resource Planner (RP), Transmission Owner (TO), Transmission Planner (TP), and Transmission Service Provider (TSP).
2

For purposes of this item, aggregate Demand is the Demand aggregated at each bus under item 1 that is identified by a Transmission Owner as a load serving bus. A Load Serving Entity is responsible
for providing this information, generally through coordination with the Transmission Owner.
3

Including synchronous condensers and pumped storage.

Page 12 of 19

steady-state
(Items marked with an asterisk indicate data that vary
with system operating state or conditions. Those items
may have different data provided for different modeling
scenarios)

real power capabilities in 3a above
station service auxiliary load for normal plant configuration
(provide data in the same manner as that required for aggregate
Demand under item 2, above).
d. regulated bus* and voltage set point* (as typically provided by
the TOP)
e. machine MVA base
f. generator step up transformer data (provide same data as that
required for transformer under item 6, below)
g. generator type (hydro, wind, fossil, solar, nuclear, etc)
h. in-service status*
AC Transmission Line or Circuit [TO]
a. impedance parameters (positive sequence)
b. susceptance (line charging)
c. ratings (normal and emergency)*
d. in-service status*
DC Transmission systems [TO]
Transformer (voltage and phase-shifting) [TO]
a. nominal voltages of windings
b. impedance(s)
c. tap ratios (voltage or phase angle)*
d. minimum and maximum tap position limits
e. number of tap positions (for both the ULTC and NLTC)
f. regulated bus (for voltage regulating transformers)*
g. ratings (normal and emergency)*
h. in-service status*
Reactive compensation (shunt capacitors and reactors) [TO]
a. admittances (MVars) of each capacitor and reactor
b. regulated voltage band limits* (if mode of operation not fixed)
c. mode of operation (fixed, discrete, continuous, etc.)
d. regulated bus* (if mode of operation not fixed)
e. in-service status*
Static Var Systems [TO]
c.

4.

5.
6.

7.

8.

dynamics
(If a user-written model(s) is submitted
in place of a generic or library model, it
must include the characteristics of the
model, including block diagrams, values
and names for all model parameters,
and a list of all state variables)
6.
7.
8.
9.
10.

Wind Turbine Data [GO]
Photovoltaic systems [GO]
Static Var Systems and FACTS [GO, TO, LSE]
DC system models [TO]
Other information requested by the Planning
Coordinator or Transmission Planner necessary
for modeling purposes. [BA, GO, LSE, TO, TSP]

Page 13 of 19

short circuit

purposes. [BA, GO, LSE, TO, TSP]

steady-state
(Items marked with an asterisk indicate data that vary
with system operating state or conditions. Those items
may have different data provided for different modeling
scenarios)

9.

dynamics
(If a user-written model(s) is submitted
in place of a generic or library model, it
must include the characteristics of the
model, including block diagrams, values
and names for all model parameters,
and a list of all state variables)

a. reactive limits
b. voltage set point*
c. fixed/switched shunt, if applicable
d. in-service status*
Other information requested by the Planning Coordinator or
Transmission Planner necessary for modeling purposes. [BA, GO, LSE,
TO, TSP]

Page 14 of 19

short circuit

Application Guidelines
Guidelines and Technical Basis
For purposes of jointly developing steady-state, dynamics, and short circuit modeling data
requirements and reporting procedures under Requirement R1, if a Transmission Planner (TP)
and Planning Coordinator (PC) mutually agree, a TP may collect and aggregate some or all data
from providing entities, and the TP may then provide that data directly to the PC(s) on behalf of
the providing entities. The submitting entities are responsible for getting the data to both the
TP and the PC, but nothing precludes them from arriving at mutual agreements for them to
provide it to the TP, who then provides it to the PC. Such agreement does not relieve the
submitting entity from responsibility under the standard, nor does it make the consolidating
entity liable for the submitting entities’ compliance under the standard (in essence, nothing
precludes parties from agreeing to consolidate or act as a conduit to pass the data, and it is in
fact encouraged in certain circumstances, but the requirement is aimed at the act of submitting
the data). Notably, there is no requirement for the TP to provide data to the PC. The intent, in
part, is to address potential concerns from entities that they would otherwise be responsible
for the quality, nature, and sufficiency of the data provided by other entities.
The requirement in Part 1.3 to include specifications for distribution or posting of the data
requirements and reporting procedures could be accomplished in many ways, to include
posting on a Web site, distributing directly, or through other methods that the Planning
Coordinator and each of its Transmission Planners develop.
An entity submitting data per the requirements of this standard who needs to determine the PC
for the area, as a starting point, should contact the local Transmission Owner (TO) for
information on the TO’s PC. Typically, the PC will be the same for both the local TO and those
entities connected to the TO’s system. If this is not the case, the local TO’s PC can typically
provide contact information on other PCs in the area. If the entity (e.g., a Generator Owner
[GO]) is requesting connection of a new generator, the entity can determine who the PC is for
that area at the time a generator connection request is submitted. Often the TO and PC are the
same entity, or the TO can provide information on contacting the PC. The entity should specify
as the reason for the request to the TO that the entity needs to provide data to the PC
according to this standard. Nothing in the proposed requirement language of this standard is
intended to preclude coordination between entities such that one entity, serving only as a
conduit, provides the other entity’s data to the PC. This can be accomplished if it is mutually
agreeable by, for example, the GO (or other entity), TP, and the PC. This does not, however,
relieve the original entity from its obligations under the standard to provide data, nor does it
pass on the compliance obligation of the entity. The original entity is still accountable for
making sure that the data has been provided to the PC according to the requirements of this
standard.
The standard language recognizes that differences exist among the Interconnections.
Presently, the Eastern/Quebec and Texas Interconnections build seasonal cases on an annual
basis, while the Western Interconnection builds cases on a continuous basis throughout the
year. The intent of the standard is not to change established processes and procedures in each
of the Interconnections, but to create a framework to support both what is already in place or

Page 15 of 19

Application Guidelines
what it may transition into in the future, and to provide further guidance in a common platform
for the collection of data that is necessary for the building of the Interconnection-wide case(s).
The construct that these standards replace did not specifically list which Functional Entities
were required to provide specific data. Attachment 1 specifically identifies the entities
responsible for the data required for the building of the Interconnection-wide case(s).
Rationale:

During development of this standard, text boxes were embedded within the standard to explain
the rationale for various parts of the standard. Upon BOT approval, the text from the rationale
text boxes was moved to this section.
Rationale for R1:
This requirement consolidates the concepts from the original data requirements from MOD011-0, Requirement R1, and MOD-013-0, Requirement R1. The original requirements specified
types of steady-state and dynamics data necessary to model and analyze the steady-state
conditions and dynamic behavior or response within each Interconnection. The original
requirements, however, did not account for the collection of short circuit data also required to
perform short circuit studies. The addition of short circuit data also addresses the outstanding
directive from FERC Order No. 890, paragraph 290.
In developing a performance-based standard that would address the data requirements and
reporting procedures for model data, it was prohibitively difficult to account for all of the
detailed technical concerns associated with the preparation and submittal of model data given
that many of these concerns are dependent upon evolving industry modeling needs and
software vendor terminology and product capabilities.
This requirement establishes the Planning Coordinator jointly with its Transmission Planners as
the developers of technical model data requirements and reporting procedures to be followed
by the data owners in the Planning Coordinator’s planning area. FERC Order No. 693,
paragraphs 1155 and 1162, also direct that the standard apply to Planning Coordinators. The
inclusion of Transmission Planners in the applicability section is intended to ensure that the
Transmission Planners are able to participate jointly in the development of the data
requirements and reporting procedures.
This requirement is also consistent with the recommendations from the NERC System Analysis
and Modeling Subcommittee (SAMS) White Paper titled “Proposed Improvements for NERC
MOD Standards”, available from the December 2012 NERC Planning Committee’s agenda
package, item 3.4, beginning on page 99, here:
Aside from recommendations in support of strengthening and improving MOD-010 through
MOD-015, the SAMS paper included the following suggested improvements:
1) reduce the quantity of MOD standards;
2) add short circuit data as a requirement to the MOD standards; and
3) supply data and models:

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a.
b.
c.
d.

add requirement identifying who provides and who receives data;
identify acceptability;
standard format;
how to deal with new technologies (user written models if no standard model
exists); and
e. shareability.
4) These suggested improvements are addressed by combining the existing standards into
two new standards, one standard for the submission and collection of data, and one for
the validation of the planning models. Adding the requirement for the submittal of
short circuit data is also an improvement from the existing standards, consistent with
FERC Order No. 890, paragraph 290. In supplying data, the approach clearly identifies
what data is required and which Functional Entity is required to provide the data.
5) The requirement uses an attachment approach to support data collection. The
attachment specifically lists the entities that are required to provide each type of data
and the steady-state, dynamics, and short circuit data that is required.
6) Finally, the decision to combine steady-state, dynamics, and short circuit data
requirements into one requirement rather than three reflects that they all support the
requirement of submission of data in general.
Rationale for R2:
This requirement satisfies the directive from FERC Order No. 693, paragraph 1155, which
directs that “the planning authority should be included in this Reliability Standard because the
planning authority is the entity responsible for the coordination and integration of transmission
facilities and resource plans, as well as one of the entities responsible for the integrity and
consistency of the data.”
Rationale for R3:
In order to maintain a certain level of accuracy in the representation of a power system, the
data that is submitted must be correct, periodically checked, and updated. Data used to
perform steady-state, dynamics, and short circuit studies can change, for example, as a result of
new planned transmission construction (in comparison to as-built information) or changes
performed during the restoration of the transmission network due to weather-related events.
One set of data that changes on a more frequent basis is load data, and updates to load data
are needed when new improved forecasts are created.
This requirement provides a mechanism for the Planning Coordinator and Transmission Planner
(that does not exist in the current standards) to collect corrected data from the entities that
have the data. It provides a feedback loop to address technical concerns related to the data
when the Planning Coordinator or Transmission Planner identifies technical concerns, such as
concerns about the usability of data or simply that the data is not in the correct format and
cannot be used. The requirement also establishes a time-frame for response to address
timeliness.

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Rationale for R4:
This requirement will replace MOD-014 and MOD-015.
This requirement recognizes the differences among Interconnections in model building
processes, and it creates an obligation for Planning Coordinators to make available data for its
planning area.
The requirement creates a clear expectation that Planning Coordinators will make available
data that they collect under Requirement R2 in support of their respective Interconnectionwide case(s). While different entities in each Interconnection create the Interconnection-wide
case(s), the requirement to submit the data to the “ERO or its designee” supports a framework
whereby NERC, in collaboration and agreement with those other organizations, can designate
the appropriate organizations in each Interconnection to build the specific Interconnectionwide case(s). It does not prescribe a specific group or process to build the larger
Interconnection-wide case(s), but only requires the Planning Coordinators to make available
data in support of their creation, consistent with the SAMS Proposed Improvements to NERC
MOD Standards (at page 3) that, “industry best practices and existing processes should be
considered in the development of requirements, as many entities are successfully coordinating
their efforts.” (Emphasis added).
This requirement is about the Planning Coordinator’s obligation to make information available
for use in the Interconnection-wide case(s); it is not a requirement to build the Interconnectionwide case(s).
For example, under current practice, the Eastern Interconnection Reliability Assessment Group
(ERAG) builds the Eastern Interconnection and Quebec Interconnection-wide cases, the
Western Electricity Coordinating Council (WECC) builds the Western Interconnection-wide
cases, and the Electric Reliability Council of Texas (ERCOT) builds the Texas Interconnectionwide cases. This requirement does not require a change to that construct, and, assuming
continued agreement by those organizations, ERAG, WECC, and ERCOT could be the “designee”
for each Interconnection contemplated by this requirement. Similarly, the requirement does
not prohibit transition, and the requirement remains for the Planning Coordinators to make
available the information to the ERO or to whomever the ERO has coordinated with and
designated as the recipient of such information for purposes of creation of each of the
Interconnection–wide cases.
Version History
Version

Date

Action

Change Tracking

1

February 6,
2014

Adopted by the NERC Board of
Trustees.

Developed to consolidate
and replace MOD-010-0,
MOD -011-0, MOD-012-0,
MOD-013-1, MOD-014-0,
and MOD-015-0.1

1

May 1, 2014

FERC Order issued approving

See Implementation Plan

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MOD-032-1.

posted on the Reliability
Standards web page for
details on enforcement
dates for Requirements.

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