COORDONNATEUR
DE LA FIABILITÉ
Demande R-3699-2009
Direction Contrôle des mouvements d’énergie
NORMES DE FIABILITÉ DE LA NERC - MOD
(VERSION ANGLAISE)
Original : 2013-05-09
HQCMÉ-8, Document 2.10
(En liasse)
Standard MOD-004-1 — Capacity Benefit Margin
A. Introduction
1.
Title:
Capacity Benefit Margin
2.
Number:
MOD-004-1
3.
Purpose: To promote the consistent and reliable calculation, verification,
preservation, and use of Capacity Benefit Margin (CBM) to support analysis and
system operations.
4.
Applicability:
4.1. Load-Serving Entities.
4.2. Resource Planners.
4.3. Transmission Service Providers.
4.4. Balancing Authorities.
4.5. Transmission Planners, when their associated Transmission Service Provider has
elected to maintain CBM.
5.
Effective Date:
First day of the first calendar quarter that is twelve months beyond
the date that this standard is approved by applicable regulatory authorities, or in those
jurisdictions where regulatory approval is not required, the standard becomes effective
on the first day of the first calendar quarter that is twelve months beyond the date this
standard is approved by the NERC Board of Trustees.
B. Requirements
R1. The Transmission Service Provider that maintains CBM shall prepare and keep current
a “Capacity Benefit Margin Implementation Document” (CBMID) that includes, at a
minimum, the following information: [Violation Risk Factor: Lower] [Time Horizon:
Operations Planning, Long-term Planning]
R1.1.
The process through which a Load-Serving Entity within a Balancing Authority
Area associated with the Transmission Service Provider, or the Resource
Planner associated with that Balancing Authority Area, may ensure that its need
for Transmission capacity to be set aside as CBM will be reviewed and
accommodated by the Transmission Service Provider to the extent Transmission
capacity is available.
R1.2.
The procedure and assumptions for establishing CBM for each Available
Transfer Capability (ATC) Path or Flowgate.
R1.3.
The procedure for a Load-Serving Entity or Balancing Authority to use
Transmission capacity set aside as CBM, including the manner in which the
Transmission Service Provider will manage situations where the requested use
of CBM exceeds the amount of CBM available.
R2. The Transmission Service Provider that maintains CBM shall make available its current
CBMID to the Transmission Operators, Transmission Service Providers, Reliability
Coordinators, Transmission Planners, Resource Planners, and Planning Coordinators
that are within or adjacent to the Transmission Service Provider’s area, and to the Load
Serving Entities and Balancing Authorities within the Transmission Service Provider’s
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Standard MOD-004-1 — Capacity Benefit Margin
area, and notify those entities of any changes to the CBMID prior to the effective date
of the change. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
R3. Each Load-Serving Entity determining the need for Transmission capacity to be set
aside as CBM for imports into a Balancing Authority Area shall determine that need
by: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
R3.1.
R3.2.
Using one or more of the following to determine the GCIR:

Loss of Load Expectation (LOLE) studies

Loss of Load Probability (LOLP) studies

Deterministic risk-analysis studies

Reserve margin or resource adequacy requirements established by other
entities, such as municipalities, state commissions, regional transmission
organizations, independent system operators, Regional Reliability
Organizations, or regional entities
Identifying expected import path(s) or source region(s).
R4. Each Resource Planner determining the need for Transmission capacity to be set aside
as CBM for imports into a Balancing Authority Area shall determine that need by:
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
R4.1.
R4.2.
Using one or more of the following to determine the GCIR:

Loss of Load Expectation (LOLE) studies

Loss of Load Probability (LOLP) studies

Deterministic risk-analysis studies

Reserve margin or resource adequacy requirements established by other
entities, such as municipalities, state commissions, regional transmission
organizations, independent system operators, Regional Reliability
Organizations, or regional entities
Identifying expected import path(s) or source region(s).
R5. At least every 13 months, the Transmission Service Provider that maintains CBM shall
establish a CBM value for each ATC Path or Flowgate to be used for ATC or Available
Flowgate Capability (AFC) calculations during the 13 full calendar months (months 214) following the current month (the month in which the Transmission Service Provider
is establishing the CBM values). This value shall: [Violation Risk Factor: Lower]
[Time Horizon: Operations Planning]
R5.1.
Reflect consideration of each of the following if available:

Any studies (as described in R3.1) performed by Load-Serving Entities for
loads within the Transmission Service Provider’s area

Any studies (as described in R4.1) performed by Resource Planners for
loads within the Transmission Service Provider’s area
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Standard MOD-004-1 — Capacity Benefit Margin

R5.2.
Any reserve margin or resource adequacy requirements for loads within the
Transmission Service Provider’s area established by other entities, such as
municipalities, state commissions, regional transmission organizations,
independent system operators, Regional Reliability Organizations, or
regional entities
Be allocated as follows:

For ATC Paths, based on the expected import paths or source regions
provided by Load-Serving Entities or Resource Planners

For Flowgates, based on the expected import paths or source regions
provided by Load-Serving Entities or Resource Planners and the
distribution factors associated with those paths or regions, as determined
by the Transmission Service Provider
R6. At least every 13 months, the Transmission Planner shall establish a CBM value for
each ATC Path or Flowgate to be used in planning during each of the full calendar
years two through ten following the current year (the year in which the Transmission
Planner is establishing the CBM values). This value shall: [Violation Risk Factor:
Lower] [Time Horizon: Long-term Planning]
R6.1.
R6.2.
Reflect consideration of each of the following if available:

Any studies (as described in R3.1) performed by Load-Serving Entities for
loads within the Transmission Planner’s area

Any studies (as described in R4.1) performed by Resource Planners for
loads within the Transmission Planner’s area

Any reserve margin or resource adequacy requirements for loads within the
Transmission Planner’s area established by other entities, such as
municipalities, state commissions, regional transmission organizations,
independent system operators, Regional Reliability Organizations, or
regional entities
Be allocated as follows:

For ATC Paths, based on the expected import paths or source regions
provided by Load-Serving Entities or Resource Planners

For Flowgates, based on the expected import paths or source regions
provided by Load-Serving Entities or Resource Planners and the distribution
factors associated with those paths or regions, as determined by the
Transmission Planner.
R7. Less than 31 calendar days after the establishment of CBM, the Transmission Service
Provider that maintains CBM shall notify all the Load-Serving Entities and Resource
Planners that determined they had a need for CBM on the Transmission Service
Provider’s system of the amount of CBM set aside. [Violation Risk Factor: Lower]
[Time Horizon: Operations Planning]
R8. Less than 31 calendar days after the establishment of CBM, the Transmission Planner
shall notify all the Load-Serving Entities and Resource Planners that determined they
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Standard MOD-004-1 — Capacity Benefit Margin
had a need for CBM on the system being planned by the Transmission Planner of the
amount of CBM set aside. [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
R9. The Transmission Service Provider that maintains CBM and the Transmission Planner
shall each provide (subject to confidentiality and security requirements) copies of the
applicable supporting data, including any models, used for determining CBM or
allocating CBM over each ATC Path or Flowgate to the following: [Violation Risk
Factor: Lower] [Time Horizon: Operations Planning, Long-term Planning]
R9.1.
Each of its associated Transmission Operators within 30 calendar days of their
making a request for the data.
R9.2.
To any Transmission Service Provider, Reliability Coordinator, Transmission
Planner, Resource Planner, or Planning Coordinator within 30 calendar days of
their making a request for the data.
R10. The Load-Serving Entity or Balancing Authority shall request to import energy over
firm Transfer Capability set aside as CBM only when experiencing a declared NERC
Energy Emergency Alert (EEA) 2 or higher. [Violation Risk Factor: Lower] [Time
Horizon: Same-day Operations]
R11. When reviewing an Arranged Interchange using CBM, all Balancing Authorities and
Transmission Service Providers shall waive, within the bounds of reliable operation,
any Real-time timing and ramping requirements. [Violation Risk Factor: Medium]
[Time Horizon: Same-day Operations]
R12. The Transmission Service Provider that maintains CBM shall approve, within the
bounds of reliable operation, any Arranged Interchange using CBM that is submitted by
an “energy deficient entity 1 ” under an EEA 2 if: [Violation Risk Factor: Medium]
[Time Horizon: Same-day Operations]
R12.1. The CBM is available
R12.2. The EEA 2 is declared within the Balancing Authority Area of the “energy
deficient entity,” and
R12.3. The Load of the “energy deficient entity” is located within the Transmission
Service Provider’s area.
C. Measures
1
M1.
Each Transmission Service Provider that maintains CBM shall produce its CBMID
evidencing inclusion of all information specified in R1. (R1)
M2.
Each Transmission Service Provider that maintains CBM shall have evidence (such
as dated logs and data, copies of dated electronic messages, or other equivalent
evidence) to show that it made the current CBMID available to the Transmission
Operators, Transmission Service Providers, Reliability Coordinators, Transmission
Planners, and Planning Coordinators specified in R2, and that prior to any change to
the CBMID, it notified those entities of the change. (R2)
See Attachment 1-EOP-002-0 for explanation.
Adopted by NERC Board of Trustees: November 13, 2008
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Standard MOD-004-1 — Capacity Benefit Margin
M3.
Each Load-Serving Entity that determined a need for Transmission capacity to be set
aside as CBM shall provide evidence (including studies and/or requirements) that it
met the criteria in R3. (R3)
M4.
Each Resource Planner that determined a need for Transmission capacity to be set
aside as CBM shall provide evidence (including studies and/or requirements) that it
met the criteria in R4. (R4)
M5.
Each Transmission Service Provider that maintains CBM shall provide evidence
(such as studies, requirements, and dated CBM values) that it established 13 months
of CBM values consistent with the requirements in R5.1 and allocated the values
consistent with the requirements in R5.2. (Note that CBM values may legitimately be
zero.) (R5)
M6.
Each Transmission Planner with an associated Transmission Service Provider that
maintains CBM shall provide evidence (such as studies, requirements, and dated
CBM values) that it established CBM values for years two through ten consistent
with the requirements in R6.1 and allocated the values consistent with the
requirements in R6.2. Inclusion of GCIR based on R6.1 and R6.2 within the
transmission base case meets this requirement. (Note that CBM values may
legitimately be zero.) (R6)
M7.
Each Transmission Service Provider that maintains CBM shall provide evidence
(such as dated e-mail, data, or other records) that it notified the entities described in
R7 of the amount of CBM set aside. (R7)
M8.
Each Transmission Planner with an associated Transmission Service Provider that
maintains CBM shall provide evidence (such as e-mail, data, or other records) that it
notified the entities described in R8 of the amount of CBM set aside. (R8)
M9.
Each Transmission Service Provider that maintains CBM and each Transmission
Planner shall provide evidence including copies of dated requests for data supporting
the calculation of CBM along with other evidences such as copies of electronic
messages or other evidence to show that it provided the required entities with copies
of the supporting data, including any models, used for allocating CBM as specified in
R9. (R9)
M10.
Each Load-Serving Entity and Balancing Authority shall provide evidence (such as
logs, copies of tag data, or other data from its Reliability Coordinator) that at the time
it requested to import energy using firm Transfer Capability set aside as CBM, it was
in an EEA 2 or higher. (R10)
M11.
Each Balancing Authority and Transmission Service Provider shall provide evidence
(such as operating logs and tag data) that it waived Real-time timing and ramping
requirements when approving an Arranged Interchange using CBM (R11)
M12.
Each Transmission Service Provider that maintains CBM shall provide evidence
including copies of CBM values along with other evidence (such as tags, reports, and
supporting data) to show that it approved any Arranged Interchange meeting the
criteria in R12. (R12)
D. Compliance
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Standard MOD-004-1 — Capacity Benefit Margin
1. Compliance Monitoring Process
1.1. Compliance Enforcement Authority (CEA)
Regional Entity.
1.2. Compliance Monitoring Period and Reset Time Frame
Not applicable.
1.3. Data Retention
-
The Transmission Service Provider that maintains CBM shall maintain its
current, in force CBMID and any prior versions of the CBMID that were in
force during the past three calendar years plus the current year to show
compliance with R1.
-
The Transmission Service Provider that maintains CBM shall maintain
evidence to show compliance with R2, R5, R7, R9, and R12 for the most
recent three calendar years plus the current year.
-
The Load-Serving Entity shall each maintain evidence to show compliance
with R3 and R10 for the most recent three calendar years plus the current
year.
-
The Resource Planner shall each maintain evidence to show compliance
with R4 for the most recent three calendar years plus the current year.
-
The Transmission Planner shall maintain evidence to show compliance with
R6, R8, and R9 for the most recent three calendar years plus the current
year.
-
The Balancing Authority shall maintain evidence to show compliance with
R10 and R11 for the most recent three calendar years plus the current year.
-
The Transmission Service Provider shall maintain evidence to show
compliance with R11 for the most recent three calendar years plus the
current year.
-
If an entity is found non-compliant, it shall keep information related to the
non-compliance until found compliant.
-
The Compliance Enforcement Authority shall keep the last audit records and
all requested and subsequently submitted audit records.
1.4. Compliance Monitoring and Enforcement Processes:
The following processes may be used:
-
Compliance Audits
-
Self-Certifications
-
Spot Checking
-
Compliance Violation Investigations
-
Self-Reporting
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Standard MOD-004-1 — Capacity Benefit Margin
-
Complaints
1.5. Additional Compliance Information
None.
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Standard MOD-004-1 — Capacity Benefit Margin
Violation Severity Levels
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R1.
The Transmission Service
Provider that maintains CBM
has a CBMID that does not
incorporate changes that have
been made within the last three
months.
The Transmission Service
Provider that maintains CBM
has a CBMID that does not
incorporate changes that have
been made more than three, but
not more than six, months ago.
OR
The CBM maintaining
Transmission Service Provider’s
CBMID does not address one of
the sub requirements.
The Transmission Service
Provider that maintains CBM
has a CBMID that does not
incorporate changes that have
been made more than six, but
not more than twelve, months
ago.
OR
The CBM maintaining
Transmission Service Provider’s
CBMID does not address two of
the sub requirements.
The Transmission Service
Provider that maintains CBM
has a CBMID that does not
incorporate changes that have
been made more than twelve
months ago.
OR
The Transmission Service
Provider that maintains CBM
does not have a CBMID;
OR
The CBM maintaining
Transmission Service Provider’s
CBMID does not address three
of the sub requirements.
R2.
The Transmission Service
Provider that maintains CBM
notifies one or more of the
entities specified in R2 of a
change in the CBM ID after the
effective date of the change, but
not more than 30 calendar days
after the effective date of the
change.
The Transmission Service
Provider that maintains CBM
notifies one or more of the
entities specified in R2 of a
change in the CBM ID 30 or
more calendar days but not
more than 60 calendar days after
the effective date of the change.
The Transmission Service
Provider that maintains CBM
notifies one or more of the
entities specified in R2 of a
change in the CBM ID 60 or
more calendar days but not
more than 90 calendar days after
the effective date of the change.
OR
The Transmission Service
Provider that maintains CBM
made available the CBMID to at
least one, but not all, of the
entities specified in R2.
The Transmission Service
Provider that maintains CBM
notifies one or more of the
entities specified in R2 of a
change in the CBM ID more
than 90 calendar days after the
effective date of the change.
OR
The Transmission Service
Provider that maintains CBM
made available the CBMID to
none of the entities specified in
R2.
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Standard MOD-004-1 — Capacity Benefit Margin
R#
Lower VSL
Moderate VSL
High VSL
Severe VSL
R3.
The Load-Serving Entity did not
use one of the methods
described in R3.1
OR
The Load-Serving Entity did not
identify paths or regions as
described in R3.2
The Load-Serving Entity did
not use one of the methods
described in R3.1
AND
The Load-Serving Entity did not
identify paths or regions as
described in R3.2
R4
The Resource Planner did not
use one of the methods
described in R4.1
OR
The Resource Planner did not
identify paths or regions as
described in R4.2
The Resource Planner did not
use one of the methods
described in R4.1
AND
The Resource Planner did not
identify paths or regions as
described in R4.2
R5.
The Transmission Service
Provider that maintains CBM
established CBM more than 16
months, but not more than 19
months, after the last time the
values were established.
OR
The Transmission Service
Provider that maintains CBM
did not consider one or more of
the items described in R5.1 that
was available.
OR
The Transmission Service
Provider that maintains CBM
did not base the allocation on
one or more paths or regions as
The Transmission Service
Provider that maintains CBM
established CBM more than 13
months, but not more than 16
months, after the last time the
values were established.
Adopted by NERC Board of Trustees: November 13, 2008
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
The Transmission Service
Provider that maintains CBM
established CBM more than 19
months, but not more than 22
months, after the last time the
values were established.
The Transmission Service
Provider that maintains CBM
established CBM more than 22
months after the last time the
values were established.
OR
The Transmission Service
Provider that maintains CBM
failed to establish an initial
value for CBM.
OR
The Transmission Service
Provider that maintains CBM
did not consider one or more of
the items described in R5.1 that
was available, and did not base
the allocation on one or more
Page 9 of 13
Standard MOD-004-1 — Capacity Benefit Margin
R#
Lower VSL
Moderate VSL
High VSL
described in R5.2.
R6.
The Transmission Planner with
an associated Transmission
Service Provider that maintains
CBM established CBM for each
of the years 2 through 10 more
than 13 months, but not more
than 16 months, after the last
time the values were
established.
The Transmission Planner with
an associated Transmission
Service Provider that maintains
CBM established CBM for each
of the years 2 through 10 more
than 16 months, but not more
than 19 months, after the last
time the values were
established.
OR
The Transmission Planner with
an associated Transmission
Service Provider that maintains
CBM did not consider one or
more of the items described in
R6.1 that was available.
OR
The Transmission Planner with
an associated Transmission
Service Provider that maintains
CBM did not base the allocation
Adopted by NERC Board of Trustees: November 13, 2008
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Severe VSL
paths or regions as described in
R5.2
The Transmission Planner with
an associated Transmission
Service Provider that maintains
CBM established CBM for each
of the years 2 through 10 more
than 19 months, but not more
than 22 months, after the last
time the values were
established.
The Transmission Planner with
an associated Transmission
Service Provider that maintains
CBM established CBM for each
of the years 2 through 10 more
than 22 months after the last
time the values were
established.
OR
The Transmission Planner with
an associated Transmission
Service Provider that maintains
CBM failed to establish an
initial value for CBM for each
of the years 2 through 10.
OR
The Transmission Planner with
an associated Transmission
Service Provider that maintains
CBM did not consider one or
more of the items described in
Page 10 of 13
Standard MOD-004-1 — Capacity Benefit Margin
R#
Lower VSL
Moderate VSL
High VSL
on one or more paths or regions
as described in R6.2
Severe VSL
R6.1 that was available, and did
not base the allocation on one or
more paths or regions as
described in R6.2
R7.
The Transmission Service
Provider that maintains CBM
notified all the entities as
required, but did so in 31 or
more days, but less than 45
days.
The Transmission Service
Provider that maintains CBM
notified all the entities as
required, but did so in 45 or
more days, but less than 60
days.
The Transmission Service
Provider that maintains CBM
notified all the entities as
required, but did so in 60 or
more days, but less than 75
days.
OR
The Transmission Service
Provider that maintains CBM
notified at least one, but not all,
of the entities as required.
The Transmission Service
Provider that maintains CBM
notified all the entities as
required, but did so in 75 or
more days,
OR
The Transmission Service
Provider that maintains CBM
notified none of the entities as
required.
R8.
The Transmission Planner with
an associated Transmission
Service Provider that maintains
CBM notified all the entities as
required, but did so in 31 or
more days, but less than 45
days.
The Transmission Planner with
an associated Transmission
Service Provider that maintains
CBM notified all the entities as
required, but did so in 45 or
more days, but less than 60
days.
The Transmission Planner with
an associated Transmission
Service Provider that maintains
CBM notified all the entities as
required, but did so in 60 or
more days, but less than 75
days.
OR
The Transmission Planner with
The Transmission Planner with
an associated Transmission
Service Provider that maintains
CBM notified all the entities as
required, but did so in 75 or
more days,
OR
The Transmission Planner with
an associated Transmission
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Page 11 of 13
Standard MOD-004-1 — Capacity Benefit Margin
R#
R9.
Lower VSL
The Transmission Service
Provider or Transmission
Planner provided a requester
specified in R9 with the
supporting data, including
models, used to allocate CBM
more than 30, but not more than
45, days after the submission of
the request.
Moderate VSL
The Transmission Service
Provider or Transmission
Planner provided a requester
specified in R9 with the
supporting data, including
models, used to allocate CBM
more than 45, but not more than
60, days after the submission of
the request.
High VSL
an associated Transmission
Service Provider that maintains
CBM notified at least one, but
not all, of the entities as
required.
Service Provider that maintains
CBM notified none of the
entities as required.
The Transmission Service
Provider or Transmission
Planner provided a requester
specified in R9 with the
supporting data, including
models, used to allocate CBM
more than 60, but not more than
75, days after the submission of
the request.
OR
The Transmission Service
Provider or Transmission
Planner provided at least one,
but not all, of the requesters
specified in R9 with the
supporting data, including
models, used to allocate CBM.
The Transmission Service
Provider or Transmission
Planner provided a requester
specified in R9 with the
supporting data, including
models, used to allocate CBM
more than 75 days after the
submission of the request.
OR
The Transmission Service
Provider or Transmission
Planner provided none of the
requesters specified in R9 with
the supporting data, including
models, used to allocate CBM.
R10.
N/A
N/A
N/A
A Load-Serving Entity or
Balancing Authority requested
to schedule energy over CBM
while not in an EEA 2 or higher.
N/A
A Balancing Authority or
Transmission Service Provider
denied an Arranged Interchange
using CBM based on timing or
ramping requirements without a
reliability reason to do so.
R11.
N/A
N/A
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Severe VSL
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Standard MOD-004-1 — Capacity Benefit Margin
R#
Lower VSL
Moderate VSL
High VSL
R12.
N/A
N/A
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Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
N/A
Severe VSL
The Transmission Service
Provider failed to approve an
Arranged Interchange for CBM
that met the criteria described in
R12 without a reliability reason
to do so.
Page 13 of 13
Standard MOD-004-1 — Capacity Benefit Margin
Appendix QC-MOD-004-1
Provisions specific to the standard MOD-004-1 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A. Introduction
1.
Title:
Capacity Benefit Margin
2.
Number:
MOD-004-1
3.
Purpose:
No specific provision
4.
Applicability: No specific provision
5.
Effective Date:
5.1. Adoption of the standard by the Régie de l'énergie: Month xx 201x
5.2. Adoption of the appendix by the Régie de l'énergie: Month xx 201x
5.3. Effective date of the standard and its appendix in Québec: Month xx 201x
6.Scope:
No specific provision
B. Requirements
No specific provision
C. Measures
No specific provision
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
The Régie de l’énergie is responsible, in Québec, for compliance enforcement with
respect to the reliability standard and its appendix that it adopts.
1.2. Compliance Monitoring Period and Reset Time Frame
No specific provision
1.3. Data Retention
No specific provision
1.4. Compliance Monitoring and Enforcement Processes
No specific provision
1.5. Additional Compliance Information
No specific provision
2.
Violation Severity Levels
No specific provision
Adopted by the Régie de l’énergie (Décision D-201x-xxxx) : Month xx, 201x
Page QC-1 de 2
Standard MOD-004-1 — Capacity Benefit Margin
Appendix QC-MOD-004-1
Provisions specific to the standard MOD-004-1 applicable in Québec
Version Revision History of the Appendix
VersionRevisi
on
Adoption Date
Action
Change Tracking
0
Month xx, 201x
Effective DateNew appendix
New
Adopted by the Régie de l’énergie (Décision D-201x-xxxx) : Month xx, 201x
Page QC-2 de 2
Standard MOD-006-0 — Procedure for the Use of CBM Values
A.
Introduction
1.
Title:
Procedures for the Use of Capacity Benefit Margin Values
2.
Number:
MOD-006-0
3.
Purpose: To promote the consistent and uniform use of transmission Transfer Capability
margins calculations among transmission system users,
4.
Applicability:
4.1.
5.
B.
Transmission Service Provider
Effective Date:
April 1, 2005
Requirements
R1. Each Transmission Service Provider shall document its procedure on the use of Capacity
Benefit Margin (CBM) (scheduling of energy against a CBM reservation). The procedure
shall include the following three components:
R1.1. Require that CBM be used only after the following steps have been taken (as time
permits): all non-firm sales have been terminated, Direct-Control Load Management
has been implemented, and customer interruptible demands have been interrupted.
CBM may be used to reestablish Operating Reserves.
R1.2. Require that CBM shall only be used if the Load-Serving Entity calling for its use is
experiencing a generation deficiency and its Transmission Service Provider is also
experiencing Transmission Constraints relative to imports of energy on its transmission
system.
R1.3. Describe the conditions under which CBM may be available as Non-Firm
Transmission Service.
R2. Each Transmission Service Provider shall make its CBM use procedure available on a web
site accessible by the Regional Reliability Organizations, NERC, and transmission users..
C.
Measures
M1. The Transmission Service Provider’s procedure for the use of CBM (scheduling of energy
against a CBM preservation) shall meet Reliability Standard MOD-006-0_R1.
M2. The Transmission Service Provider’s procedure for the use of CBM (scheduling of energy
against a CBM preservation) shall be available on a web site accessible by the Regional
Reliability Organizations, NERC, and transmission users.
D.
Compliance
1.
Compliance Monitoring Process
1.1.
1.2.
Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations
Compliance Monitoring Period and Reset Timeframe
Each Regional Reliability Organization shall report compliance and violations to
NERC via the NERC compliance reporting process.
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
1 of 2
Standard MOD-006-0 — Procedure for the Use of CBM Values
2.
E.
1.3.
Data Retention
None specified.
1.4.
Additional Compliance Information
None.
Levels of Non-Compliance
2.1.
Level 1:
The Transmission Service Provider’s procedure for use of CBM is
available and addresses only two of the three requirements for such documentation as
listed above under Reliability Standard MOD-006-0_R1.
2.2.
Level 2:
Not applicable.
2.3.
Level 3:
Not applicable.
2.4.
Level 4:
The Transmission Service Provider’s procedure for use of CBM
addresses one or none of the three requirements as listed above under Reliability
Standard MOD-006-0_R1, or is not available.
Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
September 17,
2007
Corrected R1. — changed “preservation” to
“reservation.”
Errata
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
2 of 2
Standard MOD-006-0 — Procedures for the Use of Capacity Benefit Margin Values
Appendix QC-MOD-006-0
Provisions specific to the standard MOD-006-0 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A. Introduction
1.
Title:
Procedures for the Use of Capacity Benefit Margin Values
2.
Number:
MOD-006-0
3.
Purpose:
No specific provision
4.
Applicability: No specific provision
5.
Effective Date:
5.1. Adoption date of the standard by the Régie de l'énergie: Month xx 201x
5.2. Adoption date of the appendix by the Régie de l'énergie: Month xx 201x
5.3. Effective date of the standard and its appendix in Québec: Month xx 201x
6.Scope:
Interconnection paths of the Main Transmission System (MTS)
B. Requirements
No specific provision
C. Measures
No specific provision
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
The Régie de l'énergie is responsible, in Québec, for compliance monitoring with respect
to the reliability standard and its appendix that it adopts.
1.2. Compliance Monitoring Period and Reset Timeframe
No specific provision
1.3. Data Retention
No specific provision
1.4. Additional Compliance Information
No specific provision
2.
Levels of Non-Compliance
No specific provision
E. Regional Differences
No specific provision
Adopted by Régie de l’énergie (Décision D-201x-xxxx) : Month xx, 201x
Page QC-1
Standard MOD-006-0 — Procedures for the Use of Capacity Benefit Margin Values
Appendix QC-MOD-006-0
Provisions specific to the standard MOD-006-0 applicable in Québec
Version Revision History of the Appendix
VersionR
evision
Adoption Date
Action
Change Tracking
0
Month xx, 201x
NEffective Dateew appendix
New
Adopted by Régie de l’énergie (Décision D-201x-xxxx) : Month xx, 201x
Page QC-2
Standard MOD-007-0 — Documentation of the Use of CBM
A. Introduction
1.
Title:
Documentation of the Use of Capacity Benefit Margin
2.
Number:
MOD-007-0
3.
Purpose:
To promote the consistent and uniform application of Transfer Capability margin
calculations among transmission system users by developing methodologies for calculating
Capacity Benefit Margin (CBM). This methodology shall comply with NERC definitions for
CBM, the NERC Reliability Standards, and applicable Regional criteria.
4.
Applicability:
4.1. Transmission Service Provider
5.
Effective Date:
April 1, 2005
B. Requirements
R1.
Each Transmission Service Provider that uses CBM shall report (to the Regional Reliability
Organization, NERC and the transmission users) the use of CBM by the Load-Serving Entities’
Loads on its system, except for CBM sales as Non-Firm Transmission Service. (This use of
CBM shall be consistent with the Transmission Service Provider’s procedure for use of CBM.)
R2.
The Transmission Service Provider shall post the following three items within 15 calendar days
after the use of CBM for an Energy Emergency. This posting shall be on a web site accessible
by the Regional Reliability Organizations, NERC, and transmission users.
R2.1.
Circumstances.
R2.2.
Duration.
R2.3.
Amount of CBM used.
C. Measures
M1. The Transmission Service Provider shall have evidence that it posted an after-the-fact
disclosure that energy was scheduled against a CBM preservation (for purposes other than
Non-Firm Transmission Sales) on a website accessible by the Regional Reliability
Organizations, NERC, and transmission users.
M2. If the Transmission Service Provider had energy scheduled against a CBM preservation (for
purposes other than Non-Firm Transmission Sales) the Transmission Service Provider shall
have evidence it posted an after-the-fact disclosure that includes the elements required by
Reliability Standard MOD-007_R2.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Within 15 calendar days of the use of CBM (excluding Non-Firm Transmission Sales)
1.3. Data Retention
None specified.
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
1 of 2
Standard MOD-007-0 — Documentation of the Use of CBM
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Not applicable.
2.2. Level 2:
Information pertaining to the use of CBM during an Energy Emergency was
provided, but was not made available on a web site accessible by the Regional Reliability
Organizations, NERC, and transmission users, or meets only two of the three
requirements as listed in Reliability Standard MOD-007-0_R2.
2.3. Level 3:
Not applicable.
2.4. Level 4:
After the use of CBM (excluding Non-Firm Transmission Sales),
information pertaining to the use of CBM was provided but meets one or none of the
three requirements as listed above under Reliability Standard MOD-007-0_R2, or no
information was provided.
E. Regional Differences
1.
None identified.
Version History
Version
0
Date
Action
Change Tracking
April 1, 2005
Effective Date
New
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
2 of 2
Standard MOD-007-0 — Documentation of the Use of CBM
Appendix QC-MOD-007-0
Provisions specific to the standard MOD-007-0 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A. Introduction
1.
Title:
Documentation of the Use of CBM
2.
Number:
MOD-007-0
3.
Purpose:
No specific provision
4.
Applicability: No specific provision
5.
Effective Date:
5.1. Adoption of the standard by the Régie de l'énergie: Month xx 201x
5.2. Adoption of the appendix by the Régie de l'énergie: Month xx 201x
5.3. Effective date of the standard and its appendix in Québec: Month xx 201x
6.Scope: Interconnection paths of the Main Transmission System (MTS)
B. Requirements
No specific provision
C. Measures
No specific provision
D. Compliance
1.
Compliance Monitoring Responsibility
The Régie de l'énergie is responsible, in Québec, for compliance monitoring with respect
to the reliability standard and its appendix it adopts.
1.1. Compliance Monitoring Responsibility
No specific provision
1.2. Compliance Monitoring Period and Reset Time Frame
No specific provision
1.3. Data Retention
No specific provision
1.4. Additional Compliance Information
No specific provision
2.
Levels of Non-Compliance
No specific provision
Adopted by Régie de l’énergie (Décision D-201x-xxxx) : Month xx, 201x
Page QC-1 de 2
Standard MOD-007-0 — Documentation of the Use of CBM
Appendix QC-MOD-007-0
Provisions specific to the standard MOD-007-0 applicable in Québec
E. Regional Variances
No specific provision
Version Revision History of the Appendix
VersionRevisi
on
Adoption Date
Action
Change Tracking
0
Month xx, 201x
Effective DateNew appendix
New
Adopted by Régie de l’énergie (Décision D-201x-xxxx) : Month xx, 201x
Page QC-2 de 2
Standard MOD-010-0 — Steady-State Data for Transmission System Modeling and Simulation
A. Introduction
1.
Title:
Steady-State Data for Modeling and Simulation of the Interconnected
Transmission System
2.
Number:
3.
Purpose:
To establish consistent data requirements, reporting procedures, and system
models to be used in the analysis of the reliability of the Interconnected Transmission Systems.
4.
Applicability:
MOD-010-0
4.1. Transmission Owners specified in the data requirements and reporting procedures of
MOD-011-0_R1
4.2. Transmission Planners specified in the data requirements and reporting procedures of
MOD-011-0_R1
4.3. Generator Owners specified in the data requirements and reporting procedures of MOD011-0_R1
4.4. Resource Planners specified in the data requirements and reporting procedures of MOD011-0_R1
5.
Effective Date:
April 1, 2005
B. Requirements
R1.
The Transmission Owners, Transmission Planners Generator Owners, and Resource Planners
(specified in the data requirements and reporting procedures of MOD-011-0_R1) shall provide
appropriate equipment characteristics, system data, and existing and future Interchange
Schedules in compliance with its respective Interconnection Regional steady-state modeling
and simulation data requirements and reporting procedures as defined in Reliability Standard
MOD-011-0_R1.
R2.
The Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners
(specified in the data requirements and reporting procedures of MOD-011-0_R1) shall provide
this steady-state modeling and simulation data to the Regional Reliability Organizations,
NERC, and those entities specified within Reliability Standard MOD-011-0_R1. If no schedule
exists, then these entities shall provide the data on request (30 calendar days).
C. Measures
M1. The Transmission Owner, Transmission Planner, Generator Owner, and Resource Planner,
(specified in the data requirements and reporting procedures of MOD-011-0_R1) shall have
evidence that it provided equipment characteristics, system data, and Interchange Schedules for
steady-state modeling and simulation to the Regional Reliability Organizations and NERC as
specified in Standard MOD-010-0_R1 and MOD-010-0_R2.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Decision D-201x-xxxx) : Month xx, 201x
1 of 2
Standard MOD-010-0 — Steady-State Data for Transmission System Modeling and Simulation
As specified within the applicable reporting procedures (Reliability Standard MOD-0110_R2-M1). If no schedule exists, then on request (30 calendar days.)
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Steady-state data was provided, but was incomplete in one of the seven
areas identified in Reliability Standard MOD-011-0_R1.
2.2. Level 2:
Not applicable.
2.3. Level 3:
Steady-state data was provided, but was incomplete in two or more of the
seven areas identified in Reliability Standard MOD-011-0_R1.
2.4. Level 4:
Steady-state data was not provided.
E. Regional Differences
1.
None identified.
Version History
Version
0
Date
Action
Change Tracking
April 1, 2005
Effective Date
New
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Decision D-201x-xxxx) : Month xx, 201x
2 of 2
Standard MOD-010-0 — Steady State Data for Transmission System Modeling and
Simulation
Appendix QC-MOD-010-0
Provisions specific to the standard MOD-010-0 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A.
Introduction
1.
Title:
Steady State Data for Modeling and Simulation of the Interconnected
Transmission System
2.
Number:
MOD-010-0
3.
Purpose:
No specific provision
4.
Applicability:
Functions
4.1.
Transmission Owners specified by the Regional Reliability Organization
4.2.
Transmission Planners specified by the Regional Reliability Organization
4.3.
Generator Owners specified by the Regional Reliability Organization
4.4.
Resource Planners
Facilities
No specific provision specified by the Regional Reliability Organization
5.
Effective Date:
5.1.
Adoption of the standard by the Régie de l’énergie: Month xx 201x
5.2.
Adoption of the appendix by the Régie de l’énergie: Month xx 201x
5.3.
Effective date of the standard and its appendix in Québec: Month xx 201x
6.Scope: Main Transmission System (MTS)
B.
Requirements
Specific provision : The requirements R1 and R2 supersede from the standard.
R1. The Transmission Owners, Transmission Planners Generator Owners, and Resource Planners
(specified by the Regional Reliability Organization) shall provide appropriate equipment
characteristics, system data, and existing and future Interchange Schedules in compliance with
its respective Quebec’s Interconnection Regional steady-state modeling and simulation data
requirements and reporting procedures.
R2. The Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners
(specified by the Regional Reliability Organization) shall provide this steady-state modeling
and simulation data to its Regional Reliability OrganizationPlanning Coordinator (Planning
Authority), NERC, and those entities specified by its Regional Reliability Organization. If no
schedule exists, then these entities shall provide the data on request (30 calendar days).
C.
Measures
Specific provision : The measure M1 supersede from the standard.
Adopted by Régie de l’énergie (Decision D-201x-xxxx): Month xx, 201x
Page QC-1 of 3
Standard MOD-010-0 — Steady State Data for Transmission System Modeling and
Simulation
Appendix QC-MOD-010-0
Provisions specific to the standard MOD-010-0 applicable in Québec
M1. The Transmission Owner, Transmission Planner, Generator Owner, and Resource Planner
(specified by the Regional Reliability Organization) shall have evidence that it provided
equipment characteristics, system data, and Interchange Schedules for steady-state modeling
and simulation to the Planning Coordinator (Planning Authority)Regional Reliability
Organizations and NERC as specified in Standard MOD-010-0_R1 and MOD-010-0_R2.
Adopted by Régie de l’énergie (Decision D-201x-xxxx): Month xx, 201x
Page QC-2 of 3
Standard MOD-010-0 — Steady State Data for Transmission System Modeling and
Simulation
Appendix QC-MOD-010-0
Provisions specific to the standard MOD-010-0 applicable in Québec
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
The Régie de l'énergie is responsible, in Québec, for compliance monitoring with
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Timeframe
As specified within the applicable reporting procedures of the Regional Reliability
Organization. If no schedule exists, then on request (30 calendar days.)
1.3.
Data Retention
No specific provision
1.4.
Additional Compliance Information
No specific provision
2.
E.
Levels of Non-Compliance
2.1.
Level 1: Steady-state data was provided, but was incomplete.
2.2.
Level 2: No specific provision
2.3.
Level 3: Not applicable
2.4.
Level 4: No specific provision
Regional Differences
No specific provision
F.Violation Risk Factor
No specific provision
VersionRevision History of the Appendix
VersionRevisi
on
Adoption Date
Action
Change Tracking
10
Month xx, 201x
Effective DateNew appendix
New
Adopted by Régie de l’énergie (Decision D-201x-xxxx): Month xx, 201x
Page QC-3 of 3
Standard MOD-012-0 — Dynamics Data for Transmission System Modeling and Simulation
A. Introduction
1.
Title:
Dynamics Data for Modeling and Simulation of the Interconnected
Transmission System.
2.
Number:
3.
Purpose:
To establish consistent data requirements, reporting procedures, and system
models to be used in the analysis of the reliability of the interconnected transmission systems.
4.
Applicability:
MOD-012-0
4.1. Transmission Owners specified in the data requirements and reporting procedures of
MOD-013-0_R1
4.2. Transmission Planners specified in the data requirements and reporting procedures of
MOD-013-0_R1
4.3. Generator Owners specified in the data requirements and reporting procedures of MOD013-0_R1
4.4. Resource Planners specified in the data requirements and reporting procedures of MOD013-0_R1
5.
Effective Date:
April 1, 2005
B. Requirements
R1.
The Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners
(specified in the data requirements and reporting procedures of MOD-013-0_R1) shall provide
appropriate equipment characteristics and system data in compliance with the respective
Interconnection-wide Regional dynamics system modeling and simulation data requirements
and reporting procedures as defined in Reliability Standard MOD-013-0_R1.
R2.
The Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners
(specified in the data requirements and reporting procedures of MOD-013-0_R1) shall provide
dynamics system modeling and simulation data to its Regional Reliability Organization(s),
NERC, and those entities specified within the applicable reporting procedures identified in
Reliability Standard MOD-013-0_R1. If no schedule exists, then these entities shall provide
data on request (30 calendar days).
C. Measures
M1. The Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners
(specified in the data requirements and reporting procedures of MOD-013-0_R1) shall each
have evidence that it provided equipment characteristics and system data for dynamics system
modeling and simulation in accordance with Reliability Standard MOD-012-0_R1 and
Reliability Standard MOD-012-0_R2.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Decision D-201x-xxx) : Month xx, 201x
1 of 2
Standard MOD-012-0 — Dynamics Data for Transmission System Modeling and Simulation
1.2. Compliance Monitoring Period and Reset Timeframe
As specified within the applicable reporting procedures (Reliability Standard MOD013-0). If no schedule exists, then on request (30 calendar days.)
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Dynamics data was provided, but was incomplete in one of the four areas
identified in Reliability Standard MOD-013-0_R1.
2.2. Level 2:
Not Applicable.
2.3. Level 3:
Dynamics data was provided, but was incomplete in two or more of the four
areas identified in Reliability Standard MOD-013-0_R1.
2.4. Level 4:
Dynamics data was not provided.
E. Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
September 16, 2005
Changed references to MOD-013-0 R4
to MOD-013-0 R1 in Applicability,
Requirements, and Measures (4 in all).
Errata
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Decision D-201x-xxx) : Month xx, 201x
2 of 2
Standard MOD-012-0 — Dynamics Data for Transmission System Modeling and
Simulation
Appendix QC-MOD-012-0
Provisions specific to the standard MOD-012-0 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A. Introduction
1.
Title:
Dynamics Data for Modeling and Simulation of the Interconnected
Transmission System
2.
Number:
MOD-012-0
3.
Purpose:
No specific provision
4.
Applicability:
Functions
4.1. Transmission Owners specified by the Regional Reliability Organization
4.2. Transmission Planners specified by the Regional Reliability Organization
4.3. Generator Owners specified by the Regional Reliability Organization
4.4. Resource Planners
Facilities
4.5.No specific provision specified by the Regional Reliability Organization
5.
Effective Date:
5.1. Adoption date of the standard by the Régie de l'énergie : Month xx 201x
5.2. Adoption date of the appendix by the Régie de l'énergie : Month xx 201x
5.3. Effective date of the standard and its appendix in Québec : Month xx 201x
6.Scope:
Main Transmission System (MTS)
B. Requirements
Specific provision : The requirements R1 and R2 supersede from the standard.
R1. The Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners
(specified by the Regional Reliability Organization) shall provide appropriate equipment
characteristics and system data in compliance with the respective Quebec’s Interconnectionwide Regional dynamics system modeling and simulation data requirements and reporting
procedures.
R2. The Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners
(specified by the Regional Reliability Organization) shall provide dynamics system modeling
and simulation data to its Regional Reliability Organization(s), NERC, and those entities
specified within the applicable reporting proceduresPlanning Coordinator (Planning
Authority). If no schedule exists, then these entities shall provide data on request (30 calendar
days).
C. Measures
Adopted by Régie de l’énergie (Decision D-201x-xxxx) : Month xx, 201x
Page QC-1 de 3
Standard MOD-012-0 — Dynamics Data for Transmission System Modeling and
Simulation
Appendix QC-MOD-012-0
Provisions specific to the standard MOD-012-0 applicable in Québec
Specific provision : The measure M1 supersede from the standard.
M1. The Transmission Owners, Transmission Planners, Generator Owners, and Resource Planners
(specified by the Regional Reliability Organization) shall each have evidence that it provided
equipment characteristics and system data for dynamics system modeling and simulation in
accordance with Reliability Standard MOD-012-0_R1 and Reliability Standard MOD-0120_R2to the Planning Coordinator (Planning Authority).
Adopted by Régie de l’énergie (Decision D-201x-xxxx) : Month xx, 201x
Page QC-2 de 3
Standard MOD-012-0 — Dynamics Data for Transmission System Modeling and
Simulation
Appendix QC-MOD-012-0
Provisions specific to the standard MOD-012-0 applicable in Québec
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
The Régie de l'énergie is responsible, in Québec, for compliance monitoring with respect
to the reliability standard and its appendix that it adopts.
1.2. Compliance Monitoring Period and Reset Timeframe
As specified within the applicable reporting procedures of the Regional Reliability
Organization. If no schedule exists, then on request (30 calendar days.)
1.3. Data Retention
No specific provision
1.4. Additional Compliance Information
No specific provision
2.
Levels of Non-Compliance
2.1.
Niveau 1 :
Dynamics data was provided, but was incomplete.
2.2.
Niveau 2 :
No specific provision
2.3.
Niveau 3 :
Not applicable
2.4.
Niveau 4 :
No specific provision
E. Regional Differences
No specific provision
F.Violation Risk Factor
No specific provision
Appendix VersionRevision History
VersionR
evision
Adoption Date
Action
Change Tracking
10
Month xx, 201x
Effective DateNew appendix
New
Adopted by Régie de l’énergie (Decision D-201x-xxxx) : Month xx, 201x
Page QC-3 de 3
S ta n d a rd MOD-016-1.1 — Ac tu a l a n d Fo re c a s t De m a n d s , Ne t En e rg y fo r Lo a d , Co n tro lla b le DS M
A. Introduction
1.
Title:
Documentation of Data Reporting Requirements for Actual and
Forecast Demands, Net Energy for Load, and Controllable Demand-Side
Management
2.
Number:
3.
Purpose: Ensure that accurate, actual Demand data is available to support
assessments and validation of past events and databases. Forecast Demand data is
needed to perform future system assessments to identify the need for system
reinforcements for continued reliability. In addition, to assist in proper real-time
operating, Load information related to controllable Demand-Side Management (DSM)
programs is needed.
4.
Applicability:
MOD-016-1.1
4.1. Planning Authority.
4.2. Regional Reliability Organization.
5.
Effective Date:
May 13, 2009
B. Requirements
R1. The Planning Authority and Regional Reliability Organization shall have
documentation identifying the scope and details of the actual and forecast (a) Demand
data, (b) Net Energy for Load data, and (c) controllable DSM data to be reported for
system modeling and reliability analyses.
R1.1.
The aggregated and dispersed data submittal requirements shall ensure that
consistent data is supplied for Reliability Standards TPL-005, TPL-006, MOD010, MOD-011, MOD-012, MOD-013, MOD-014, MOD-015, MOD-016,
MOD-017, MOD-018, MOD-019, MOD-020, and MOD-021.
The data submittal requirements shall stipulate that each Load-Serving Entity
count its customer Demand once and only once, on an aggregated and
dispersed basis, in developing its actual and forecast customer Demand values.
R2. The Regional Reliability Organization shall distribute its documentation required in
Requirement 1 and any changes to that documentation, to all Planning Authorities that
work within its Region.
R2.1.
The Regional Reliability Organization shall make this distribution within 30
calendar days of approval.
R3. The Planning Authority shall distribute its documentation required in R1 for reporting
customer data and any changes to that documentation, to its Transmission Planners and
Load-Serving Entities that work within its Planning Authority Area.
R3.1.
The Planning Authority shall make this distribution within 30 calendar days of
approval.
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Page 1 of 3
S ta n d a rd MOD-016-1.1 — Ac tu a l a n d Fo re c a s t De m a n d s , Ne t En e rg y fo r Lo a d , Co n tro lla b le DS M
C. Measures
M1. The Planning Authority and Regional Reliability Organization’s documentation for
actual and forecast customer data shall contain all items identified in R1.
M2. The Regional Reliability Organization shall have evidence it provided its actual and
forecast customer data reporting requirements as required in Requirement 2.
M3. The Planning Authority shall have evidence it provided its actual and forecast customer
data and reporting requirements as required in Requirement 3.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor for Planning Authority: Regional Reliability Organization.
Compliance Monitor for Regional Reliability Organization: NERC.
1.2. Compliance Monitoring Period and Reset Time Frame
One calendar year.
1.3. Data Retention
For the Regional Reliability Organization and Planning Authority: Current
version of the documentation.
For the Compliance Monitor: Three years of audit information.
1.4. Additional Compliance Information
The Regional Reliability Organization and Planning Authority shall each
demonstrate compliance through self-certification or audit (periodic, as part of
targeted monitoring or initiated by complaint or event), as determined by the
Compliance Monitor.
2.
Levels of Non-Compliance
2.1. Level 1: Documentation does not address completeness and double counting of
customer data.
2.2. Level 2: Documentation did not address one of the three types of data required in
R1 (Demand data, Net Energy for Load data, and controllable DSM data).
2.3. Level 3: No evidence documentation was distributed as required.
2.4. Level 4: Either the documentation did not address two of the three types of data
required in R1 (Demand data, Net Energy for Load data, and controllable DSM
data) or there was no documentation.
E. Regional Differences
None identified.
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Page 2 of 3
S ta n d a rd MOD-016-1.1 — Ac tu a l a n d Fo re c a s t De m a n d s , Ne t En e rg y fo r Lo a d , Co n tro lla b le DS M
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
1
November 1, 2006
Corrected sequential numbering
problem in Sections R2. and R3.
Errata
1
May 2, 2006
Adopted by NERC Board of
Trustees
1.1
October 29, 2008
BOT adopted errata changes;
updated version number to “1.1”
Errata
1.1
May 13, 2009
FERC Approved — Updated
Effective Date
Revised
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Page 3 of 3
Standard MOD-016-1.1 — Actual and Forecast Demands, Net Energy for Load,
Controllable DSM
Appendix QC-MOD-016-1.1
Provisions specific to the standard MOD-016-1.1 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A.
Introduction
1.
Title:
Documentation of Data Reporting Requirements for Actual and Forecast
Demands, Net Energy for Load, and Controllable Demand-Side Management
2.
Number:
MOD-016-1.1
3.
Purpose:
No specific provision
4.
Applicability:
No specific provision
4.1.Not applicable in Québec
5.
Effective Date:
5.1.
Adoption of the standard by the Régie de l’énergie: Month xx 201x
5.2.
Adoption of the appendix by the Régie de l’énergie: Month xx 201x
5.3.
Effective date of the standard and its appendix in Québec: Month xx 201x
6.Scope:
B.
Québec Interconnection
Requirements
No specific provision
R1.Not applicable in Québec
R2.No specific provision
C.
Measures
No specific provision
M1.Not applicable in Québec
M2.No specific provision
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
The Régie de l’énergie is responsible, in Québec, for compliance monitoring with
respect to the reliability standard and its appendix that it adopts.
The NERC remains responsible for compliance monitoring of the Regional
Reliability Organization.
1.2.
Compliance Monitoring Period and Reset Timeframe
No specific provision
Adopted by the Régie de l’énergie (Decision D-201x-xxxx): Month xx, 201x
Page QC-1 of 2
Standard MOD-016-1.1 — Actual and Forecast Demands, Net Energy for Load,
Controllable DSM
Appendix QC-MOD-016-1.1
Provisions specific to the standard MOD-016-1.1 applicable in Québec
1.3.
Data Retention
No specific provision
1.4.
Additional Compliance Information
No specific provision
2.
Levels of Non-Compliance
No specific provision
E.
Regional Differences
No specific provision
F.Violation Risk Factor
No specific provision
Version Revision History of the Appendix
VersionRevisi
on
Adoption Date
Action
Change Tracking
0
Month xx, 201x
Effective DateNew appendix
New
Adopted by the Régie de l’énergie (Decision D-201x-xxxx): Month xx, 201x
Page QC-2 of 2
S ta n d a rd MOD-017-0.1 — Ag g re g a te d Ac tu a l a n d Fo re c a s t De m a n d s a n d Ne t En erg y fo r
Lo a d
A. Introduction
1.
Title:
Aggregated Actual and Forecast Demands and Net Energy for Load
2.
Number:
MOD-017-0.1
3.
Purpose: To ensure that assessments and validation of past events and databases can
be performed, reporting of actual Demand data is needed. Forecast demand data is
needed to perform future system assessment to identify the need for system
reinforcement for continued reliability. In addition to assist in proper real-time
operating, load information related to controllable Demand-Side Management
programs is needed.
4.
Applicability:
4.1. Load-Serving Entity.
4.2. Planning Authority.
4.3. Resource Planner.
5.
Effective Date:
May 13, 2009
B. Requirements
R1. The Load-Serving Entity, Planning Authority and Resource Planner shall each provide
the following information annually on an aggregated Regional, subregional, Power
Pool, individual system, or Load-Serving Entity basis to NERC, the Regional
Reliability Organizations, and any other entities specified by the documentation in
Standard MOD-016-1_R1.
R1.1.
Integrated hourly demands in megawatts (MW) for the prior year.
R1.2.
Monthly and annual peak hour actual demands in MW and Net Energy for
Load in gigawatthours (GWh) for the prior year.
R1.3.
Monthly peak hour forecast demands in MW and Net Energy for Load in GWh
for the next two years.
R1.4.
Annual Peak hour forecast demands (summer and winter) in MW and annual
Net Energy for load in GWh for at least five years and up to ten years into the
future, as requested.
C. Measures
M1. Load-Serving Entity, Planning Authority, and Resource Planner shall each provide
evidence to its Compliance Monitor that it provided load data per Standard MOD-0170_R1.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Page 1 of 2
S ta n d a rd MOD-017-0.1 — Ag g re g a te d Ac tu a l a n d Fo re c a s t De m a n d s a n d Ne t En erg y fo r
Lo a d
Compliance Monitor: Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Time Frame
Annually or as specified in the documentation (Standard MOD-016-1_R1.)
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
3.
Level 1:
Did not provide actual and forecast demands and Net Energy for Load
data in one of the four areas as required in Reliability Standard MOD-017-0_R1.
4.
Level 2:
Did not provide actual and forecast demands and Net Energy for Load
data in two of the four areas as required in Reliability Standard MOD-017-0_R1.
5.
Level 3:
Did not provide actual and forecast demands and Net Energy for Load
data in three of the four areas as required in Reliability Standard MOD-017-0_R1.
6.
Level 4:
Did not provide actual and forecast demands and Net Energy for Load
data in any of the areas as required in Reliability Standard MOD-017-0_R1.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
April 18, 2008
Revised R1. And D1.2. to reflect
update in version from “MOD-0160_R1” to MOD-016-1_R1.”
Errata
0
February 8, 2005
Adopted By NERC Board of Trustees
0.1
October 29, 2008 BOT adopted errata changes; updated
version number to “0.1”
0.1
May 13, 2009
Errata
FERC Approved — Updated Effective Revised
Date
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Page 2 of 2
Standard MOD-017-0.1 — Aggregated Actual and Forecast Demands and Net Energy for
Load
Appendix QC-MOD-017-0.1
Provisions specific to the standard MOD-017-0.1 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A.
Introduction
1.
Title:
Aggregated Actual and Forecast Demands and Net Energy for Load
2.
Number:
MOD-017-0.1
3.
Purpose:
No specific provision
Applicability: No specific provision Québec Interconnection
Functions
No specific provision
Facilities
This standard only applies to the facilities of the Québec Interconnection.
4.
No specific provision
5.
Effective Date:
5.1.
Adoption of the standard by the Régie de l’énergie: Month xx 201x
5.2.
Adoption of the appendix by the Régie de l’énergie: Month xx 201x
5.3.Effective date of the standard and its appendix in Québec: Month xx 201x
6.5.3. Scope:
B.
Québec Interconnection
Requirements
Specific provision applicable to requirement R1:No specific provision reference to the standard
MOD-016-1 is replaced by reference to the standard MOD-016-1.1
C.
Measures
Specific provisionNo specific provision: reference to the standard MOD-017-0 is replaced by
reference to the standard MOD-17-0.1
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
The Régie de l’énergie is responsible, in Québec, for compliance monitoring with
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Timeframe
Specific provision: reference to the standard MOD-016-1 is replaced by reference to
the standard MOD-16-1.1
No specific provision
1.3.
Data Retention
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-1 of 4
Standard MOD-017-0.1 — Aggregated Actual and Forecast Demands and Net Energy for
Load
Appendix QC-MOD-017-0.1
Provisions specific to the standard MOD-017-0.1 applicable in Québec
No specific provision
1.4.
Additional Compliance Information
No specific provision
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-2 of 4
Standard MOD-017-0.1 — Aggregated Actual and Forecast Demands and Net Energy for
Load
Appendix QC-MOD-017-0.1
Provisions specific to the standard MOD-017-0.1 applicable in Québec
2.
Levels of Non-Compliance
Specific provisionss applicablesapplicables to non-compliance levels No specific
provision2.1, 2.2, 2.3 and 2.4: references to the standard MOD-017-0 isare replaced by
reference to the standard MOD-017-0.1
E.
Regional Differences
No specific provision
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-3 of 4
Standard MOD-017-0.1 — Aggregated Actual and Forecast Demands and Net Energy for
Load
Appendix QC-MOD-017-0.1
Provisions specific to the standard MOD-017-0.1 applicable in Québec
F.Violation Risk Factor
No specific provision
RevisionVersion History of the Appendix
RevisionVersi
on
Adoption Date
Action
Change Tracking
0
Month xx, 201x
New AppendixEffective Date
New
Adopted by the Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-4 of 4
Standard MOD-018-0 — Reports of Actual and Forecast Demand Data
A. Introduction
1.
Title:
Treatment of Nonmember Demand Data and How Uncertainties are
Addressed in the Forecasts of Demand and Net Energy for Load
2.
Number:
3.
Purpose:
To ensure that Assessments and validation of past events and databases can be
performed, reporting of actual demand data is needed. Forecast demand data is needed to
perform future system assessments to identify the need for system reinforcement for continued
reliability. In addition, to assist in proper real-time operating, load information related to
controllable Demand-Side Management programs is needed.
4.
Applicability:
MOD-018-0
4.1. Load-Serving Entity
4.2. Planning Authority
4.3. Transmission Planner
4.4. Resource Planner
5.
Effective Date:
April 1, 2005
B. Requirements
R1.
R2.
The Load-Serving Entity, Planning Authority, Transmission Planner and Resource Planner’s
report of actual and forecast demand data (reported on either an aggregated or dispersed basis)
shall:
R1.1.
Indicate whether the demand data of nonmember entities within an area or Regional
Reliability Organization are included, and
R1.2.
Address assumptions, methods, and the manner in which uncertainties are treated in
the forecasts of aggregated peak demands and Net Energy for Load.
R1.3.
Items (MOD-018-0_R1.1) and (MOD-018-0_R1.2) shall be addressed as described in
the reporting procedures developed for Standard MOD-016-0_R1.
The Load-Serving Entity, Planning Authority, Transmission Planner and Resource Planner
shall each report data associated with Reliability Standard MOD-018-0_R1 to NERC, the
Regional Reliability Organization, Load-Serving Entity, Planning Authority, and Resource
Planner on request (within 30 calendar days).
C. Measures
M1. The Load-Serving Entity, Planning Authority, Transmission Planner, and Resource Planner
shall each provide evidence to its Compliance Monitor that its actual and forecast demand data
were addressed as described in the reporting procedures developed for Reliability Standard
MOD-018-0_R1.
M2. The Load-Serving Entity, Planning Authority, Transmission Planner, and Resource Planner
shall each report current information for Reliability Standard MOD-018-0_R1 to NERC, the
Regional Reliability Organization, Load-Serving Entity, Planning Authority, and Resource
Planner on request (within 30 calendar days).
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Decision D-201x-xxxx) : Month xx, 201x
1 of 2
Standard MOD-018-0 — Reports of Actual and Forecast Demand Data
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
On Request (within 30 calendar days).
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
provided.
Information for Reliability Standard MOD-018-0 item R1.1 or R1.2 was not
2.2. Level 2:
Information for Reliability Standards MOD-018-0 items R1.1 and R1.2 was
not provided.
2.3. Level 3:
Not applicable.
2.4. Level 4:
Not applicable.
E. Regional Differences
1.
None identified.
Version History
Version
0
Date
Action
Change Tracking
April 1, 2005
Effective Date
New
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Decision D-201x-xxxx) : Month xx, 201x
2 of 2
Standard MOD-018-0 — Reports of Actual and Forecast Demand Data
Appendix QC-MOD-018-0
Provisions specific to the standard MOD-018-0 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A. Introduction
1.
Title:
Treatment of Non member Demand Data and How Uncertainties are
Addressed in the Forecasts of Demand and Net Energy for Load
2.
Number:
MOD-018-0
3.
Purpose:
No specific provision
4.
Applicability: No specific provision
5.
Effective Date:
5.1. Adoption date of the standard by the Régie de l'énergie: Month xx 201x
5.2. Adoption date of the appendix by the Régie de l'énergie: Month xx 201x
5.3. Effective date of the standard and its appendix in Québec: Month xx 201x
6.Scope:
Québec Interconnection
B. Requirements
Specific provision applicable to requirement R1.3: No specific provisionreference to the standard
MOD-016-0 is replaced by reference to the standard MOD-016-1.1
C. Measures
No specific provision
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
The Régie de l'énergie is responsible, in Québec, for compliance monitoring with respect
to the reliability standard and its appendix that it adopts.
1.2. Compliance Monitoring Period and Reset Timeframe
No specific provision
1.3. Data Retention
No specific provision
1.4. Additional Compliance Information
No specific provision
2.
Levels of Non-Compliance
No specific provision
E. Regional Differences
No specific provision
Adopted by Régie de l’énergie (Decision D-201x-xxxx) : Month xx, 201x
Page QC-1 of 2
Standard MOD-018-0 — Reports of Actual and Forecast Demand Data
Appendix QC-MOD-018-0
Provisions specific to the standard MOD-018-0 applicable in Québec
F.Violation Risk Factor
No specific provision
Appendix Revision HistoryVersion History
RevisionVersi
on
Adoption Date
01
Month xx, 201x
Action
Change Tracking
New AppendixEffective Date
New
Adopted by Régie de l’énergie (Decision D-201x-xxxx) : Month xx, 201x
Page QC-2 of 2
S ta n d a rd MOD-019-0.1 — Fo re c a s ts of In terrup tib le De m a n d s a n d DCLM Da ta
A. Introduction
1.
Title:
Reporting of Interruptible Demands and Direct Control Load
Management
2.
Number:
3.
Purpose:
To ensure that assessments and validation of past events and databases can
be performed, reporting of actual demand data is needed. Forecast demand data is
needed to perform future system assessments to identify the need for system
reinforcement for continued reliability. In addition, to assist in proper real-time
operating, load information related to controllable Demand-Side Management
programs is needed.
4.
Applicability:
MOD-019-0.1
4.1. Load-Serving Entity.
4.2. Planning Authority.
4.3. Transmission Planner.
4.4. Resource Planner.
5.
Effective Date:
May 13, 2009
B. Requirements
R1. The Load-Serving Entity, Planning Authority, Transmission Planner, and Resource
Planner shall each provide annually its forecasts of interruptible demands and Direct
Control Load Management (DCLM) data for at least five years and up to ten years into
the future, as requested, for summer and winter peak system conditions to NERC, the
Regional Reliability Organizations, and other entities (Load-Serving Entities, Planning
Authorities, and Resource Planners) as specified by the documentation in Reliability
Standard MOD-016-1_R1.
C. Measures
M1. The Load-Serving Entity, Planning Authority, Transmission Planner, and Resource
Planner shall each provide evidence to its Compliance Monitor that it provided
forecasts of interruptible demands and DCLM data per Reliability Standard MOD-0190_R1.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Each Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Time Frame
Annually or as specified in the documentation (Reliability Standard MOD-0161_R1.)
1.3. Data Retention
Page | 1
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
S ta n d a rd MOD-019-0.1 — Fo re c a s ts of In terrup tib le De m a n d s a n d DCLM Da ta
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Not applicable.
2.2. Level 2:
Not applicable.
2.3. Level 3:
Not applicable.
2.4. Level 4:
Did not provide forecasts of interruptible Demands and DCLM
data as required in Standard MOD-019-0_R1.
E. Regional Differences
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0
February 8,
2005
Approved by BOT
Revised
0
July 24, 2007
Changed reference R1. and Dl.1.2. to
“MOD-016-0_R1” to MOD-016-1_R1.”
(New version number.)
Errata
0.1
October 29,
2008
BOT adopted errata changes; updated
version number to “0.1”.
Errata
0.1
May 13, 2009
FERC Approved — Updated Effective
Date
Revised
Page | 2
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Standard MOD-019-0.1 — Forecasts of Interruptible Demands and DCLM Data
Appendix QC-MOD-019-0.1
Provisions specific to the standard MOD-019-0.1 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A.
Introduction
1.
Title:
Reporting of interruptible Demands and Direct Control Load Management
2.
Number:
MOD-019-0.1
3.
Purpose:
No specific provision
4.
Applicability: No specific provision
5.
Effective Date:
5.1.
Adoption of the standard by the Régie de l’énergie: Month xx 201x
5.2.
Adoption of the appendix by the Régie de l’énergie: Month xx 201x
5.3.
Effective date of the standard and its appendix in Québec: Month xx 201x
6.Scope:
B.
No specific provision
Requirements
Specific provision: reference to the standard MOD-016-1 is replaced by reference to the standard
MOD-016-1.1No specific provision
C.
Measures
Specific provision: reference to the standard MOD-019-0 is replaced by reference to the standard
MOD-019-0.1.
D.No specific provision
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Monitoring Responsibility
The Régie de l’énergie is responsible, in Québec, for compliance monitoring with
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Timeframe
Specific provision: reference to the standard MOD-016-1 is replaced by reference to
the standard MOD-016-1.1
1.3.No specific provision
1.3.
Data Retention
No specific provision
1.4.
Additional Compliance Information
No specific provision
2.
Levels of Non-Compliance
Adopted by the Régie de l’énergie (Decision D-201x-xxxx): Month xx, 201x
Page QC-1 of 3
Standard MOD-019-0.1 — Forecasts of Interruptible Demands and DCLM Data
Appendix QC-MOD-019-0.1
Provisions specific to the standard MOD-019-0.1 applicable in Québec
Specific provision applicable to the non-compliance level 2.4:: reference to the
standard MOD-019-0 is replaced by reference to the standard MOD-019-0.1 No
specific provision
E.
Regional Differences
No specific provision
Adopted by the Régie de l’énergie (Decision D-201x-xxxx): Month xx, 201x
Page QC-2 of 3
Standard MOD-019-0.1 — Forecasts of Interruptible Demands and DCLM Data
Appendix QC-MOD-019-0.1
Provisions specific to the standard MOD-019-0.1 applicable in Québec
F.Violation Risk Factor
No specific provision
Version Revision History of the Appendix
VersionRevisi
on
Adoption Date
0
Month xx, 201x
Action
Change Tracking
New AppendixEffective Date
New
Adopted by the Régie de l’énergie (Decision D-201x-xxxx): Month xx, 201x
Page QC-3 of 3
Standard MOD-020-0 — Providing Interruptible Demands and DCLM Data
A. Introduction
1.
Title:
Providing Interruptible Demands and Direct Control Load Management
Data to System Operators and Reliability Coordinators
2.
Number:
3.
Purpose:
To ensure that assessments and validation of past events and databases can be
performed, reporting of actual demand data is needed. Forecast demand data is needed to
perform future system assessments to identify the need for system reinforcement for continued
reliability. In addition to assist in proper real-time operating, load information related to
controllable Demand-Side Management programs is needed.
4.
Applicability:
MOD-020-0
4.1. Load-Serving Entity
4.2. Transmission Planner
4.3. Resource Planner
5.
Effective Date:
April 1, 2005
B. Requirements
R1.
The Load-Serving Entity, Transmission Planner, and Resource Planner shall each make known
its amount of interruptible demands and Direct Control Load Management (DCLM) to
Transmission Operators, Balancing Authorities, and Reliability Coordinators on request within
30 calendar days.
C. Measures
M1. The Load-Serving Entity, Transmission Planner, and Resource Planner each make known its
amount of interruptible demands and DCLM to Transmission Operators, Balancing Authorities
and Reliability Coordinators on request within 30 calendar days.
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Regional Reliability Organization.
1.2. Compliance Monitoring Period and Reset Timeframe
On request (within 30 calendar days).
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.
2.
Levels of Non-Compliance
2.1. Level 1:
Interruptible Demands and DCLM data were provided to Reliability
Coordinators, Balancing Authorities, and Transmission Operators, but were incomplete.
2.2. Level 2:
Not applicable.
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Decision D-201x-xxxx) : Month xx, 201x
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Standard MOD-020-0 — Providing Interruptible Demands and DCLM Data
2.3. Level 3:
Not applicable.
2.4. Level 4:
Interruptible Demands and DCLM data were not provided to Reliability
Coordinators, Balancing Authorities, and Transmission Operators.
E. Regional Differences
1.
None identified.
Version History
Version
0
Date
Action
Change Tracking
April 1, 2005
Effective Date
New
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005
Adopted by the Régie de l'énergie (Decision D-201x-xxxx) : Month xx, 201x
2 of 2
Standard MOD-020-0 — Providing Interruptible Demands and DCLM Data
Appendix QC-MOD-020-0
Provisions specific to the standard MOD-020-0 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A. Introduction
1.
Title:
Providing Interruptible Demands and Direct Control Load Management
Data to System Operators and Reliability Coordinators
2.
Number:
MOD-020-0
3.
Purpose:
No specific provision
4.
Applicability: No specific provision
5.
Effective Date:
5.1. Adoption date of the standard by the Régie de l'énergie: Month xx 201x
5.2. Adoption date of the appendix by the Régie de l'énergie: Month xx 201x
5.3. Effective date of the standard and its appendix in Québec: Month xx 201x
6.Scope:
No specific provision
B. Requirements
No specific provision
C. Measures
No specific provision
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
The Régie de l'énergie is responsible, in Québec, for compliance monitoring with respect
to the reliability standard and its appendix that it adopts.
1.2. Compliance Monitoring Period and Reset Timeframe
No specific provision
1.3. Data Retention
No specific provision
1.4. Additional Compliance Information
No specific provision
2.
Levels of Non-Compliance
No specific provision
E. Regional Differences
No specific provision
Adopted by Régie de l’énergie (Decision D-201x-xxxx) : Month xx, 201x
Page QC-1 de 2
Standard MOD-020-0 — Providing Interruptible Demands and DCLM Data
Appendix QC-MOD-020-0
Provisions specific to the standard MOD-020-0 applicable in Québec
Violation Risk Factor
No specific provision
Appendix RevisionVersion History
RevisionVersi
on
Adopted Date
Action
Change Tracking
01
Month xx, 201x
New AppendixEffective Date
New
Adopted by Régie de l’énergie (Decision D-201x-xxxx) : Month xx, 201x
Page QC-2 de 2
Standard MOD-021-1 — Accounting Methodology for Effects of DSM in Forecasts
A. Introduction
1.
Title:
Documentation of the Accounting Methodology for the Effects of DemandSide Management in Demand and Energy Forecasts.
2.
Number:
3.
Purpose:
To ensure that assessments and validation of past events and databases can be
performed, reporting of actual Demand data is needed. Forecast demand data is needed to
perform future system assessments to identify the need for system reinforcement for continued
reliability. In addition, to assist in proper real-time operating, load information related to
Demand-Side Management (DSM) programs is needed.
4.
Applicability:
MOD-021-1
4.1. Load-Serving Entity
4.2. Transmission Planner
4.3. Resource Planner
5.
(Proposed) Effective Date: The first day of the first calendar quarter after applicable
regulatory approval; or in those jurisdictions where no regulatory approval is required, the first
day of the first calendar quarter after Board of Trustees’ adoption.
B. Requirements
R1.
The Load-Serving Entity, Transmission Planner and Resource Planner’s forecasts shall each
clearly document how the Demand and energy effects of DSM programs (such as conservation,
time-of-use rates, interruptible Demands, and Direct Control Load Management) are addressed.
R2.
The Load-Serving Entity, Transmission Planner and Resource Planner shall each include
information detailing how Demand-Side Management measures are addressed in the forecasts
of its Peak Demand and annual Net Energy for Load in the data reporting procedures of
Standard MOD-016-0_R1.
R3.
The Load-Serving Entity, Transmission Planner and Resource Planner shall each make
documentation on the treatment of its DSM programs available to NERC on request (within 30
calendar days).
C. Measures
M1. The Load-Serving Entity, Transmission Planner and Resource Planner forecasts clearly
document how the demand and energy effects of DSM programs (such as conservation, timeof-use rates, interruptible demands, and Direct Control Load Management) are addressed.
M2. The Load-Serving Entity, Transmission Planner and Resource Planner information detailing
how Demand-Side Management measures are addressed in the forecasts of Peak Demand and
annual Net Energy for Load are included in the data reporting procedures of Reliability
Standard MOD-016-0_R1.
M3. The Load-Serving Entity, Planning Authority and Resource Planner shall each provide
evidence to its Compliance Monitor that it provided documentation on the treatment of DSM
programs to NERC as requested (within 30 calendar days).
D. Compliance
1.
Compliance Monitoring Process
1.1. Compliance Enforcement Authority
Adopted by Board of Trustees: August 5, 2010
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
1 of 2
Standard MOD-021-1 — Accounting Methodology for Effects of DSM in Forecasts
Regional Entity.
1.2. Compliance Monitoring Period and Reset Timeframe
On request (within 30 calendar days).
1.3. Compliance Monitoring and Enforcement Processes:
Compliance Audits
Self-Certifications
Spot Checking
Compliance Violation Investigations
Self-Reporting
Complaints
1.4. Data Retention
None specified.
1.5. Additional Compliance Information
None.
2.
Violation Severity Levels (no changes)
E. Regional Differences
1.
None identified.
Version History
Version
Date
Action
Change Tracking
0
April 1, 2005
Effective Date
New
0.1
April 15, 2009
R1. – comma inserted after Load-Serving
Entity
0.1
December 10, 2009
Approved by FERC — Added effective date Update
TBD
Modified to address Order No. 693
Directives contained in paragraph 1300.
1
Adopted by Board of Trustees: August 5, 2010
Adopted by the Régie de l'énergie (Décision D-201x-xxxx): Month xx, 201x
Revised.
2 of 2
Standard MOD-021-1 — Accounting Methodology for Effects of DSM in Forecasts
Appendix QC-MOD-021-1
Provisions specific to the standard MOD-021-1 applicable in Québec
This appendix establishes specific provisions for the application of the standard in Québec. Provisions of
the standard and of its appendix must be read together for the purposes of understanding and
interpretation. Where the standard and appendix differ, the appendix shall prevail.
A.
Introduction
1.
Title:
Documentation of the Accounting Methodology for the Effects of DemandSide Management in Demand and Energy Forecasts
2.
Number:
MOD-021-1
3.
Purpose:
No specific provision
4.
Applicability: No specific provision
5.
Effective Date:
5.1.
Adoption of the standard by the Régie de l’énergie: Month xx 201x
5.2.
Adoption of the appendix by the Régie de l’énergie: Month xx 201x
5.3.
Effective date of the standard and its appendix in Québec: Month xx 201x
6.Scope: Québec Interconnection
B.
Requirements
Specific provision applicable to requirement R2:No specific provision reference to the standard
MOD-016-0 is replaced by reference to the standard MOD-016-1.1
C.
Measures
Specific provisions applicable to measure M2: No specific provision reference to the
standard MOD-016-0 is replaced by reference to the standard MOD-016-1.1
D.
Compliance
1.
Compliance Monitoring Process
1.1.
Compliance Enforcement Authority
The Régie de l’énergie is responsible, in Québec, for compliance enforcement ofwith
respect to the reliability standard and its appendix that it adopts.
1.2.
Compliance Monitoring Period and Reset Timeframe
No specific provision
1.3.
Compliance Monitoring and Enforcement Processes
No specific provision
1.4.
Data Retention
No specific provision
1.5.
Additional Compliance Information
No specific provision
Adopted by Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-1 of 4
Standard MOD-021-1 — Accounting Methodology for Effects of DSM in Forecasts
Appendix QC-MOD-021-1
Provisions specific to the standard MOD-021-1 applicable in Québec
2.
Violation Severity Levels (no changes)
Requirement
Lower
Moderate
High
Severe
E1
The responsible entity’s
forecasts document how the
Demand and energy effects of
DSM programs but failed to
document how one (1) of the
following elements of the
Demand and energy effects of
DSM programs are addressed:
conservation, time-of-use rates,
interruptible Demands or Direct
Control Load Management.
The responsible entity’s
forecasts document how the
Demand and energy effects of
DSM programs but failed to
document how two (2) of the
following elements of the
Demand and energy effects of
DSM programs are addressed:
conservation, time-of-use rates,
interruptible Demands or Direct
Control Load Management.
The responsible entity’s
forecasts document how the
Demand and energy effects of
DSM programs but failed to
document how three (3) of the
following elements of the
Demand and energy effects of
DSM programs are addressed:
conservation, time-of-use rates,
interruptible Demands or Direct
Control Load Management.
The responsible entity’s
forecasts failed to document
how the Demand and energy
effects of DSM programs are
addressed.
E2
N/A
N/A
N/A
The responsible entity failed to
include information detailing
how Demand-Side Management
measure(s) are addressed in the
forecasts of its Peak Demand
and annual Net Energy for Load
in the data reporting procedures
of Standard MOD-0161.1_R10_R 1.
E3
The responsible entity provided
documentation on the treatment
of its DSM programs more than
30 calendar days but less than or
equal to 40 calendar days
following the request from
NERC.
The responsible entity provided
documentation on the treatment
of its DSM programs more than
40 calendar days but less than or
equal to 50 calendar days
following the request from
NERC.
The responsible entity provided
documentation on the treatment
of its DSM programs more than
50 calendar days but less than or
equal to 60 calendar days
following the request from
NERC.
The responsible entity provided
documentation on the treatment
of its DSM programs more than
60 calendar days following the
request from NERC.
OR
The responsible entity failed to
provide documentation on the
treatment of its DSM programs
following a request from NERC.
Adopted by Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-2 of 4
Standard MOD-021-1 — Accounting Methodology for Effects of DSM in Forecasts
Appendix QC-MOD-021-1
Provisions specific to the standard MOD-021-1 applicable in Québec
No specific provision
Adopted by Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-3 of 4
Standard MOD-021-1 — Accounting Methodology for Effects of DSM in Forecasts
Appendix QC-MOD-021-1
Provisions specific to the standard MOD-021-1 applicable in Québec
E.
Regional Differences
No specific provision
F.Violation Risk Factor
No specific provision
VersionRevision History of the Appendix
VersionRevi
sion
Adoption Date
Action
Change Tracking
0
Month xx, 201x
New AppendixEffective dateNew appendix
New
Adopted by Régie de l’énergie (Décision D-201x-xxxx): Month xx, 201x
Page QC-4 of 4