NORMES DE FIABILITÉ DE LA NERC JANVIER 2016

COORDONNATEUR

DE LA FIABILITÉ

Direction Contrôle des mouvements d’énergie Demande R-3699-2009

NORMES DE FIABILITÉ DE LA NERC

ADOPTÉES PAR LA RÉGIE DE L’ÉNERGIE,

À ÊTRE MISES EN VIGUEUR AU 1

er

JANVIER 2016

(VERSION ANGLAISE)

Original : 2015-10-

22

HQCMÉ-13, Document 2.1

(En liasse)

Standard BAL-004-0 — Time Error Correction

A. Introduction

1.

Title: Time Correction

2.

Number: BAL-004-0

3.

Purpose:

The purpose of this standard is to ensure that Time Error Corrections are conducted in a manner that does not adversely affect the reliability of the Interconnection.

4.

Applicability:

4.1.

Reliability Coordinators

4.2.

Balancing Authorities

5.

Effective Date: April 1, 2005

B. Requirements

R1.

Only a Reliability Coordinator shall be eligible to act as Interconnection Time Monitor. A single Reliability Coordinator in each Interconnection shall be designated by the NERC

Operating Committee to serve as Interconnection Time Monitor.

R2.

The Interconnection Time Monitor shall monitor Time Error and shall initiate or terminate corrective action orders in accordance with the NAESB Time Error Correction Procedure.

R3.

Each Balancing Authority, when requested, shall participate in a Time Error Correction by one of the following methods:

R3.1.

The Balancing Authority shall offset its frequency schedule by 0.02 Hertz, leaving the

Frequency Bias Setting normal; or

R3.2.

The Balancing Authority shall offset its Net Interchange Schedule (MW) by an amount equal to the computed bias contribution during a 0.02 Hertz Frequency Deviation (i.e.

20% of the Frequency Bias Setting).

R4.

Any Reliability Coordinator in an Interconnection shall have the authority to request the

Interconnection Time Monitor to terminate a Time Error Correction in progress, or a scheduled Time Error Correction that has not begun, for reliability considerations.

R4.1.

Balancing Authorities that have reliability concerns with the execution of a Time Error

Correction shall notify their Reliability Coordinator and request the termination of a

Time Error Correction in progress.

C. Measures

Not specified.

D. Compliance

Not specified.

None identified.

Adopted by NERC Board of Trustees: February 8, 2005

Effective Date: April 1, 2005

Adopted by Régie de l'énergie (decision D-2015-098): June 23, 2015

1 of 2


Version History

Version

0

0

Date

April 1, 2005

Action

Effective Date

Change Tracking

New

August 8, 2005 Removed "Proposed" from Effective Date Errata



Adopted by Régie de l'énergie (decision D-2015-098): June 23, 2015

2 of 2


Appendix QC-BAL-004-0

Provisions specific to the standard BAL-004-0 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: Time Error Correction

2.

Number: BAL-004-0

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: June 23, 2015

5.2.

Adoption of the appendix by the Régie de l’énergie: June 23, 2015

5.3.

Effective date of the standard and its appendix in Québec: January 1, 2016

B. Requirements

R1. The Reliability Coordinator is designated to act as the Interconnexion time monitor for

Québec.

C. Measures

No specific provision

D. Compliance


E. Regional Differences


Revision History

Revision Adoption Date Action

0 June 23, 2015 New appendix

Change Tracking

New

Adopted by the Régie de l’énergie (Decision D-2015-098): June 23, 2015 Page QC-1 of 1

Standard BAL-005-0.2b — Automatic Generation Control

A. Introduction

1.

Title: Automatic Generation Control

2.

Number:

BAL-005-0.2b

3.

Purpose:

This standard establishes requirements for Balancing Authority Automatic

Generation Control (AGC) necessary to calculate Area Control Error (ACE) and to routinely deploy the Regulating Reserve. The standard also ensures that all facilities and load electrically synchronized to the Interconnection are included within the metered boundary of a

Balancing Area so that balancing of resources and demand can be achieved.

4.

Applicability:

4.1.


4.2.

Generator Operators

4.3.

Transmission Operators

4.4.

Load Serving Entities

5.

Effective Date:

May 13, 2009

B. Requirements

R1.

All generation, transmission, and load operating within an Interconnection must be included within the metered boundaries of a Balancing Authority Area.

R1.1.

Each Generator Operator with generation facilities operating in an Interconnection shall ensure that those generation facilities are included within the metered boundaries of a Balancing Authority Area.

R1.2.

Each Transmission Operator with transmission facilities operating in an

Interconnection shall ensure that those transmission facilities are included within the metered boundaries of a Balancing Authority Area.

R1.3.

Each Load-Serving Entity with load operating in an Interconnection shall ensure that those loads are included within the metered boundaries of a Balancing Authority Area.

R2.

Each Balancing Authority shall maintain Regulating Reserve that can be controlled by AGC to meet the Control Performance Standard.

R3.

A Balancing Authority providing Regulation Service shall ensure that adequate metering, communications, and control equipment are employed to prevent such service from becoming a Burden on the Interconnection or other Balancing Authority Areas.

R4.

A Balancing Authority providing Regulation Service shall notify the Host Balancing

Authority for whom it is controlling if it is unable to provide the service, as well as any

Intermediate Balancing Authorities.

R5.

A Balancing Authority receiving Regulation Service shall ensure that backup plans are in place to provide replacement Regulation Service should the supplying Balancing Authority no longer be able to provide this service.

R6.

The Balancing Authority’s AGC shall compare total Net Actual Interchange to total Net

Scheduled Interchange plus Frequency Bias obligation to determine the Balancing Authority’s

ACE. Single Balancing Authorities operating asynchronously may employ alternative ACE calculations such as (but not limited to) flat frequency control. If a Balancing Authority is unable to calculate ACE for more than 30 minutes it shall notify its Reliability Coordinator.

Adopted by the Régie de l’énergie (Decision D-2013-176): October 30, 2013 Page 1 of 6


R7.

The Balancing Authority shall operate AGC continuously unless such operation adversely impacts the reliability of the Interconnection. If AGC has become inoperative, the Balancing

Authority shall use manual control to adjust generation to maintain the Net Scheduled

Interchange.

R8.

The Balancing Authority shall ensure that data acquisition for and calculation of ACE occur at least every six seconds.

R8.1.

Each Balancing Authority shall provide redundant and independent frequency metering equipment that shall automatically activate upon detection of failure of the primary source. This overall installation shall provide a minimum availability of 99.95%.

R9.

The Balancing Authority shall include all Interchange Schedules with Adjacent Balancing

Authorities in the calculation of Net Scheduled Interchange for the ACE equation.

R9.1.

Balancing Authorities with a high voltage direct current (HVDC) link to another

Balancing Authority connected asynchronously to their Interconnection may choose to omit the Interchange Schedule related to the HVDC link from the ACE equation if it is modeled as internal generation or load.

R10.

The Balancing Authority shall include all Dynamic Schedules in the calculation of Net

Scheduled Interchange for the ACE equation.

R11.

Balancing Authorities shall include the effect of ramp rates, which shall be identical and agreed to between affected Balancing Authorities, in the Scheduled Interchange values to calculate ACE.

R12.

Each Balancing Authority shall include all Tie Line flows with Adjacent Balancing Authority

Areas in the ACE calculation.

R12.1.

Balancing Authorities that share a tie shall ensure Tie Line MW metering is telemetered to both control centers, and emanates from a common, agreed-upon source using common primary metering equipment. Balancing Authorities shall ensure that megawatt-hour data is telemetered or reported at the end of each hour.

R12.2.

Balancing Authorities shall ensure the power flow and ACE signals that are utilized for calculating Balancing Authority performance or that are transmitted for Regulation

Service are not filtered prior to transmission, except for the Anti-aliasing Filters of Tie

Lines.

R12.3.

Balancing Authorities shall install common metering equipment where Dynamic

Schedules or Pseudo-Ties are implemented between two or more Balancing

Authorities to deliver the output of Jointly Owned Units or to serve remote load.

R13.

Each Balancing Authority shall perform hourly error checks using Tie Line megawatt-hour meters with common time synchronization to determine the accuracy of its control equipment.

The Balancing Authority shall adjust the component (e.g., Tie Line meter) of ACE that is in error (if known) or use the interchange meter error (I

ME

) term of the ACE equation to compensate for any equipment error until repairs can be made.

R14.

The Balancing Authority shall provide its operating personnel with sufficient instrumentation and data recording equipment to facilitate monitoring of control performance, generation response, and after-the-fact analysis of area performance. As a minimum, the Balancing

Authority shall provide its operating personnel with real-time values for ACE, Interconnection frequency and Net Actual Interchange with each Adjacent Balancing Authority Area.

R15.

The Balancing Authority shall provide adequate and reliable backup power supplies and shall periodically test these supplies at the Balancing Authority’s control center and other critical


Standard BAL-005-0.2b — Automatic Generation Control locations to ensure continuous operation of AGC and vital data recording equipment during loss of the normal power supply.

R16.

The Balancing Authority shall sample data at least at the same periodicity with which ACE is calculated. The Balancing Authority shall flag missing or bad data for operator display and archival purposes. The Balancing Authority shall collect coincident data to the greatest practical extent, i.e., ACE, Interconnection frequency, Net Actual Interchange, and other data shall all be sampled at the same time.

R17.

Each Balancing Authority shall at least annually check and calibrate its time error and frequency devices against a common reference. The Balancing Authority shall adhere to the minimum values for measuring devices as listed below:

Device Accuracy

Digital frequency transducer ≤ 0.001 Hz

MW, MVAR, and voltage transducer ≤ 0.25 % of full scale

Remote terminal unit

Potential transformer

Current transformer

≤

≤

≤

0.25 % of full scale



C. Measures

Not specified.

D. Compliance

1.

Compliance Monitoring Process

1.1.

Compliance Monitoring Responsibility

Balancing Authorities shall be prepared to supply data to NERC in the format defined below:

1.1.1.

Within one week upon request, Balancing Authorities shall provide NERC or the Regional Reliability Organization CPS source data in daily CSV files with time stamped one minute averages of: 1) ACE and 2) Frequency Error.

1.1.2.

Within one week upon request, Balancing Authorities shall provide NERC or the Regional Reliability Organization DCS source data in CSV files with time stamped scan rate values for: 1) ACE and 2) Frequency Error for a time period of two minutes prior to thirty minutes after the identified Disturbance.

1.2.

Compliance Monitoring Period and Reset Timeframe

Not specified.

1.3.

Data Retention

1.3.1.

Each Balancing Authority shall retain its ACE, actual frequency, Scheduled

Frequency, Net Actual Interchange, Net Scheduled Interchange, Tie Line meter error correction and Frequency Bias Setting data in digital format at the same scan rate at which the data is collected for at least one year.

1.3.2.

Each Balancing Authority or Reserve Sharing Group shall retain documentation of the magnitude of each Reportable Disturbance as well as the ACE charts and/or samples used to calculate Balancing Authority or



Reserve Sharing Group disturbance recovery values. The data shall be retained for one year following the reporting quarter for which the data was recorded.

1.4.

Additional Compliance Information

Not specified.

2.

Levels of Non-Compliance

Not specified.


None identified.

F. Associated Documents

1.

Appendix 1  Interpretation of Requirement R17 (February 12, 2008).

Version History

Version Date

0

0

0

0a

0a

0b

0.1b

0.1b

0.2b

0.2b

Action

February 8, 2005

April 1, 2005

Adopted by NERC Board of Trustees

Effective Date

August 8, 2005 Removed “Proposed” from Effective Date

December 19, 2007 Added Appendix 1 – Interpretation of R17 approved by BOT on May 2, 2007

January 16, 2008 Section F: added “1.”; changed hyphen to “en dash.” Changed font style for “Appendix 1” to

Arial

February 12, 2008 Replaced Appendix 1 – Interpretation of R17 approved by BOT on February 12, 2008 (BOT approved retirement of Interpretation included in

BAL-005-0a)

October 29, 2008 BOT approved errata changes; updated version number to “0.1b”

May 13, 2009 FERC approved – Updated Effective Date

March 8, 2012 Errata adopted by Standards Committee; (replaced

Appendix 1 with the FERC-approved revised interpretation of R17 and corrected standard version referenced in Interpretation by changing from “BAL-005-1” to “BAL-005-0)

September 13, 2012 FERC approved – Updated Effective Date

Change Tracking

New

New

Errata

Addition

Errata

Replacement

Errata

Addition

Errata

Addition



Appendix 1

Effective Date: August 27, 2008 (U.S.)

Interpretation of BAL-005-0 Automatic Generation Control, R17

Request for Clarification received from PGE on July 31, 2007

PGE requests clarification regarding the measuring devices for which the requirement applies, specifically clarification if the requirement applies to the following measuring devices:

•

Only equipment within the operations control room

•

Only equipment that provides values used to calculate AGC ACE

•

Only equipment that provides values to its SCADA system

•

Only equipment owned or operated by the BA

•

Only to new or replacement equipment

•

To all equipment that a BA owns or operates

BAL-005-0

R17.

Each Balancing Authority shall at least annually check and calibrate its time error and frequency devices against a common reference. The Balancing Authority shall adhere to the minimum values for measuring devices as listed below:

Device

Digital frequency transducer

MW, MVAR, and voltage transducer

Remote terminal unit

Potential transformer

Current transformer

Accuracy

≤ 0.001 Hz

≤ 0.25% of full scale




Existing Interpretation Approved by Board of Trustees May 2, 2007

BAL-005-0, Requirement 17 requires that the Balancing Authority check and calibrate its control room time error and frequency devices against a common reference at least annually. The requirement to

“annually check and calibrate” does not address any devices outside of the operations control room.

The table represents the design accuracy of the listed devices. There is no requirement within the standard to “annually check and calibrate” the devices listed in the table, unless they are included in the control center time error and frequency devices.

Interpretation provided by NERC Frequency Task Force on September 7, 2007 and Revised on

November 16, 2007

As noted in the existing interpretation, BAL-005-0 Requirement 17 applies only to the time error and frequency devices that provide, or in the case of back-up equipment may provide, input into the reporting or compliance ACE equation or provide real-time time error or frequency information to the system operator. Frequency inputs from other sources that are for reference only are excluded. The time error and frequency measurement devices may not necessarily be located in the system operations control room or owned by the Balancing Authority; however the Balancing Authority has the responsibility for the


Standard BAL-005-0.2b — Automatic Generation Control accuracy of the frequency and time error measurement devices. No other devices are included in R 17.

The other devices listed in the table at the end of R17 are for reference only and do not have any mandatory calibration or accuracy requirements.

New or replacement equipment that provides the same functions noted above requires the same calibrations. Some devices used for time error and frequency measurement cannot be calibrated as such.

In this case, these devices should be cross-checked against other properly calibrated equipment and replaced if the devices do not meet the required level of accuracy.



Appendix QC-BAL-005-0.2b

Provisions specific to the standard BAL-005-0.2b applicable in Québec


A. Introduction

1.

Title: Automatic Generation Control

2.

Number: BAL-005-0.2b

3.


4.


5.

Effective Date:

5.1.

Adoption of the standard by the Régie de l’énergie: October 30, 2013

5.2.

Adoption of the appendix by the Régie de l’énergie: October 30, 2013

5.3.


B. Requirements


C. Measures


D. Compliance

1.


1.1.


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.



1.3.

Data Retention


1.4.



2.





Adopted by the Régie de l’énergie (Decision D-2013-176): October 30, 2013 Page QC-1 of 2


Appendix QC-BAL-005-0.2b

Provisions specific to the standard BAL-005-0.2b applicable in Québec



Appendix 1




0 October 30, 2013 New appendix

Change Tracking

New


Standard COM-002-2 — Communications and Coordination

A. Introduction

1.

2.

3.

Title: Communication and Coordination

Number: COM-002-2

Purpose: To ensure Balancing Authorities, Transmission Operators, and Generator

Operators have adequate communications and that these communications capabilities are staffed and available for addressing a real-time emergency condition. To ensure communications by operating personnel are effective.

4.

Applicability

4.1.

Reliability Coordinators.

4.2.

Balancing Authorities.

4.3.

Transmission Operators.

4.4.

Generator Operators.

5.

R1.

Effective Date:

B. Requirements

January 1, 2007

Each Transmission Operator, Balancing Authority, and Generator Operator shall have communications (voice and data links) with appropriate Reliability Coordinators,

Balancing Authorities, and Transmission Operators. Such communications shall be staffed and available for addressing a real-time emergency condition.

R2.

R1.1.

Each Balancing Authority and Transmission Operator shall notify its

Reliability Coordinator, and all other potentially affected Balancing

Authorities and Transmission Operators through predetermined communication paths of any condition that could threaten the reliability of its area or when firm load shedding is anticipated.

Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall issue directives in a clear, concise, and definitive manner; shall ensure the recipient of the directive repeats the information back correctly; and shall acknowledge the response as correct or repeat the original statement to resolve any misunderstandings.

C. Measures

M1.

Each Transmission Operator, Balancing Authority and Generator Operator shall have communication facilities (voice and data links) with appropriate Reliability

Coordinators, Balancing Authorities, and Transmission Operators and shall have and provide as evidence, a list of communication facilities or other equivalent evidence that confirms that the communications have been provided to address a real-time emergency condition. (Requirement 1, part 1)

M2.

The Balancing Authority and Transmission Operator shall have and provide upon request evidence that could include but is not limited to, operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine if it notified its Reliability Coordinator, and all other potentially affected Balancing Authorities and Transmission Operators of a

Adopted by Board of Trustees: November 1, 2006

Effective Date: January 1, 2007

Adopted by the Régie de l’énergie (Decision D-2013-176): October 30, 2013

Page1 of 3

Standard COM-002-2 — Communications and Coordination condition that could threaten the reliability of its area or when firm load shedding was anticipated. (Requirement 1.1)

D. Compliance

1.


1.1.


Regional Reliability Organizations shall be responsible for compliance monitoring.

1.2.

Compliance Monitoring and Reset Time Frame

One or more of the following methods will be used to assess compliance:

Self-certification (Conducted annually with submission according to schedule.)

Spot Check Audits (Conducted anytime with up to 30 days notice given to prepare.)

Periodic Audit (Conducted once every three years according to schedule.)

Triggered Investigations (Notification of an investigation must be made within 60 days of an event or complaint of noncompliance. The entity will have up to 30 days to prepare for the investigation. An entity may request an extension of the preparation period and the extension will be considered by the Compliance Monitor on a case-by-case basis.)

2.

The Performance-Reset Period shall be 12 months from the last finding of noncompliance.

1.3.

Data Retention

Each Balancing Authority, Transmission Operator and Generator Operator shall keep evidence of compliance for the previous two calendar years plus the current year. (Measure 1)

Each Balancing Authority and Transmission Operator shall keep 90 days of historical data. (Measure 2).

If an entity is found non-compliant the entity shall keep information related to the noncompliance until found compliant or for two years plus the current year, whichever is longer.

Evidence used as part of a triggered investigation shall be retained by the entity being investigated for one year from the date that the investigation is closed, as determined by the Compliance Monitor.

The Compliance Monitor shall keep the last periodic audit report and all requested and submitted subsequent compliance records.

1.4.


None.

Levels of Non-Compliance for Transmission Operator and Balancing Authority:




Page2 of 3

Standard COM-002-2 — Communications and Coordination

2.1.

Level 1: Not applicable.

2.2.

Level 2: Not applicable .

2.3.


2.4.

Level 4: Communication did not occur as specified in R1.1.

Levels of Non-Compliance for Generator Operator: 3.

3.1.


3.2.

Level 2: Not applicable .

3.3.


3.4.

Level 4: Communication facilities are not provided to address a real-time emergency condition as specified in R1.


None identified.

Version History

Version

0

Date Action

April 1, 2005 Effective Date

0 August 8, 2005 Removed “Proposed” from Effective

Date

1 February Adopted by Board of Trustees

2006

Change Tracking

New

Errata

Revised

Revised

2006




Page3 of 3

Standard COM-002-2 — Communications and coordination

Appendix QC-COM-002-2

Provisions specific to the standard COM-002-2 applicable in Québec


A. Introduction

1.

Title: Communications and coordination

2.

Number: COM-002-2

3.


4.


5.

Effective Date:

5.1.


5.2.

Adoption of the appendix by the Régie de l’énergie: October 30 ,2013

5.3.


B. Requirements


C. Measures


D. Compliance

1.


1.1.


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.



1.3.

Data Retention


1.4.



2.

Levels of Non-Compliance for Transmission Operator and Balancing Authority:


3.

Levels of Non-Compliance for Generation Operator:





Standard COM-002-2 — Communications and coordination

Appendix QC-COM-002-2

Provisions specific to the standard COM-002-2 applicable in Québec


Revision Adoption Date

0 October 30, 2013

Action

New appendix

Change Tracking

New


Standard EOP-002-3.1 — Capacity and Energy Emergencies

A. Introduction

1.

Title

:

Capacity and Energy Emergencies

2.

Number

: EOP-002-3.1

3.

Purpose

: To ensure Reliability Coordinators and Balancing Authorities are prepared for capacity and energy emergencies.

4.

Applicability

4.1.


4.2.


4.3.

Load-Serving Entities.

5.

(Proposed) Effective Date:

First day of the first calendar quarter six months following applicable regulatory approval; or, in those jurisdictions where no regulatory approval is required, the first day of the first calendar quarter six months following Board of Trustees adoption.

B. Requirements

R1.

Each Balancing Authority and Reliability Coordinator shall have the responsibility and clear decision-making authority to take whatever actions are needed to ensure the reliability of its respective area and shall exercise specific authority to alleviate capacity and energy emergencies.

R2.

Each Balancing Authority shall, when required and as appropriate, take one or more actions as described in its capacity and energy emergency plan to reduce risks to the interconnected system.

R3.

A Balancing Authority that is experiencing an operating capacity or energy emergency shall communicate its current and future system conditions to its Reliability Coordinator and neighboring Balancing Authorities.

R4.

A Balancing Authority anticipating an operating capacity or energy emergency shall perform all actions necessary including bringing on all available generation, postponing equipment maintenance, scheduling interchange purchases in advance, and being prepared to reduce firm load.

R5.

A deficient Balancing Authority shall only use the assistance provided by the Interconnection’s frequency bias for the time needed to implement corrective actions. The Balancing Authority shall not unilaterally adjust generation in an attempt to return Interconnection frequency to normal beyond that supplied through frequency bias action and Interchange Schedule changes.

Such unilateral adjustment may overload transmission facilities.

R6.

If the Balancing Authority cannot comply with the Control Performance and Disturbance

Control Standards, then it shall immediately implement remedies to do so. These remedies include, but are not limited to:

R6.1.

Loading all available generating capacity.

R6.2.

Deploying all available operating reserve.

R6.3.

Interrupting interruptible load and exports.

R6.4.

Requesting emergency assistance from other Balancing Authorities.

R6.5.

Declaring an Energy Emergency through its Reliability Coordinator; and



R6.6.

Reducing load, through procedures such as public appeals, voltage reductions, curtailing interruptible loads and firm loads.

R7.

Once the Balancing Authority has exhausted the steps listed in Requirement 6, or if these steps cannot be completed in sufficient time to resolve the emergency condition, the Balancing

Authority shall:

R7.1.

Manually shed firm load without delay to return its ACE to zero; and

R7.2.

Request the Reliability Coordinator to declare an Energy Emergency Alert in accordance with Attachment 1-EOP-002 “Energy Emergency Alerts.”

R8.

A Reliability Coordinator that has any Balancing Authority within its Reliability Coordinator area experiencing a potential or actual Energy Emergency shall initiate an Energy Emergency

Alert as detailed in Attachment 1-EOP-002 “Energy Emergency Alerts.” The Reliability

Coordinator shall act to mitigate the emergency condition, including a request for emergency assistance if required.

R9.

When a Transmission Service Provider expects to elevate the transmission service priority of an Interchange Transaction from Priority 6 (Network Integration Transmission Service from

Non-designated Resources) to Priority 7 (Network Integration Transmission Service from designated Network Resources) as permitted in its transmission tariff:

R9.1.

The deficient Load-Serving Entity shall request its Reliability Coordinator to initiate an Energy Emergency Alert in accordance with Attachment 1-EOP-002 “Energy

Emergency Alerts.”

R9.2.

The Reliability Coordinator shall submit the report to NERC for posting on the NERC

Website, noting the expected total MW that may have its transmission service priority changed.

R9.3.

The Reliability Coordinator shall use EEA 1 to forecast the change of the priority of transmission service of an Interchange Transaction on the system from Priority 6 to

Priority 7.

R9.4.

The Reliability Coordinator shall use EEA 2 to announce the change of the priority of transmission service of an Interchange Transaction on the system from Priority 6 to

Priority 7.

C. Measures

M1.

Each Reliability Coordinator and Balancing Authority shall have and provide upon request evidence that could include but is not limited to, job descriptions, signed agreements, authority letter signed by an appropriate officer of the company, or other equivalent evidence that will be used to confirm that it meets Requirement 1.

M2.

If a Reliability Coordinator or Balancing Authority implements one or more actions described in its Capacity and Energy Emergency plan, that entity shall have and provide upon request evidence that could include but is not limited to, operator logs, voice recordings or transcripts of voice recordings, electronic communications, computer printouts or other equivalent evidence that will be used to determine if the actions it took to relieve emergency conditions were in conformance with its Capacity and Energy Emergency Plan. (Requirement 2)

M3.

If a Balancing Authority experiences an operating Capacity or Energy Emergency it shall have and provide upon request evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine if it met Requirement 3.



M4.

The Balancing Authority shall have and provide upon request evidence (such as operator logs, work orders, E-Tags, or other evidence) that it took the actions described in R4 in response to anticipating a capacity or energy emergency.

M5.

The Balancing Authority shall have and provide upon request evidence (such as operator logs, dispatch instructions, or other evidence) that it only used the assistance provided by the

Interconnection frequency bias for the time needed to implement corrective actions and did not attempt to return Interconnection frequency to normal through unilateral adjustment of generation beyond that supplied through the frequency bias action and Interchange Schedule changes. (Requirement 5)

M6.

The Balancing Authority shall have and provide upon request evidence (such as operator logs, dispatch instructions, or other evidence) that it took actions such as those listed in R6 to comply with CPS and DCS.

M7.

The Balancing Authority shall have and provide upon request evidence (such as operator logs, voice recordings, or other evidence) that it took the actions listed in R7 when unable to resolve an emergency condition.

M8.

If a Reliability Coordinator has any Balancing Authority within its Reliability Coordinator

Area that has notified the Reliability Coordinator of a potential or actual Energy Emergency, the Reliability Coordinator involved in the event shall have and provide upon request evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence to determine if it initiated an Energy Emergency Alert as specified in Requirement 8 and as detailed in Attachment 1-

EOP-002 “Energy Emergency Alerts.”

M9.

If a Transmission Service Provider expects to elevate the transmission service priority of an

Interchange Transaction from Priority 6 (Network Integration Transmission Service from Nondesignated Resources) to Priority 7 (Network Integration Transmission Service from designated Network Resources), the Reliability Coordinator involved in the event shall have and provide upon request evidence that could include, but is not limited to, NERC reports,

EEA reports, operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine if that Reliability

Coordinator met Requirements 9.2, 9.3 and 9.4.

D. Compliance

1.


1.1.

Compliance Enforcement Authority

Regional Entity

1.2.


Not Applicable.

1.3.

Compliance Monitoring and Enforcement Process

Compliance Audits

Self-Certifications

Spot Checking

Compliance Violation Investigations

Self-Reporting



Complaints

1.4.

Data Retention

For Measure 1, each Reliability Coordinator and Balancing Authority shall keep

The current in-force documents.

For Measure 2, 8 and 9 the Reliability Coordinator shall keep 90 days of historical data.

For Measure 3, 4, 5, 6, and 7 the Balancing Authority shall keep 90 days of historical data.


Evidence used as part of a triggered investigation shall be retained by the entity being investigated for one year from the date that the investigation is closed, as determined by the Compliance Monitor.


1.5.


None.


None identified.

Version History

Version Date

0

0

1

2

2

2

2.1

2.1

3

3

3.1

April 1, 2005

August 8, 2005

Action

Effective Date

Removed “Proposed” from Effective Date

September 19, 2006 Changes R7. to refer to “Requirement 6” instead of “Requirement 7”

November 1, 2006

November 1, 2006

Adopted by Board of Trustees

October 1, 2007

Corrected numbering in Section A.4.

“Applicability.”

Added to Section 1 inadvertently omitted “4.3.

Load-Serving Entities

October 29, 2008

May 13, 2009

June 4, 2010

August 5, 2010

March 8, 2012

BOT adopted errata changes; updated version number to “2.1”

FERC Approved

Modified to address Order No. 693 Directives contained in paragraphs 582.


Errata adopted by Standards Committee;

(Updated title of Attachment 1 and changed

Change Tracking

New

Errata

Errata

Revised

Errata

Errata

Errata

Revised

Revised.

New

Errata



3.1 September 13, 2012 references to Attachment 1 throughout Standard from “Attachment 1-EOP-002-0 Energy

Emergency Alert Levels” to “Attachment 1-

EOP-002 Energy Emergency Alerts”. Removed parenthetical in Requirement R9 referencing a retired Attachment in IRO-006)

FERC Approved Errata



Attachment 1-EOP-002

Energy Emergency Alerts

Introduction

This Attachment provides the procedures by which a Load Serving Entity can obtain capacity and energy when it has exhausted all other options and can no longer provide its customers’ expected energy requirements. NERC defines this situation as an “Energy Emergency.” NERC assumes that a capacity deficiency will manifest itself as an energy emergency.

The Energy Emergency Alert Procedure is initiated by the Load Serving Entity’s Reliability

Coordinator, who declares various Energy Emergency Alert levels as defined in Section B, “Energy

Emergency Alert Levels,” to provide assistance to the Load Serving Entity.

The Load Serving Entity who requests this assistance is referred to as an “Energy Deficient Entity.”

NERC recognizes that Transmission Providers are subject to obligations under FERC-approved tariffs and other agreements, and nothing in these procedures should be interpreted as changing those obligations.

A. General Requirements

1.

Initiation by Reliability Coordinator.

An Energy Emergency Alert may be initiated only by a Reliability Coordinator at 1) the Reliability Coordinator’s own request, or 2) upon the request of a Balancing Authority, or 3) upon the request of a Load Serving Entity.

1.1.

Situations for initiating alert.

An Energy Emergency Alert may be initiated for the following reasons:

• When the Load Serving Entity is, or expects to be, unable to provide its customers’ energy requirements, and has been unsuccessful in locating other systems with available resources from which to purchase, or

2.

• The Load Serving Entity cannot schedule the resources due to, for example,

Available Transfer Capability (ATC) limitations or transmission loading relief limitations.

Notification.

A Reliability Coordinator who declares an Energy Emergency Alert shall notify all Balancing Authorities and Transmission Providers in its Reliability Area. The Reliability

Coordinator shall also notify all other Reliability Coordinators of the situation via the

Reliability Coordinator Information System (RCIS). Additionally, conference calls between

Reliability Coordinators shall be held as necessary to communicate system conditions. The

Reliability Coordinator shall also notify the other Reliability Coordinators when the alert has ended.

B. Energy Emergency Alert Levels

Introduction

To ensure that all Reliability Coordinators clearly understand potential and actual energy emergencies in the Interconnection, NERC has established three levels of Energy Emergency Alerts. The

Reliability Coordinators will use these terms when explaining energy emergencies to each other. An

Energy Emergency Alert is an emergency procedure, not a daily operating practice, and is not intended as an alternative to compliance with NERC reliability standards or power supply contracts.

The Reliability Coordinator may declare whatever alert level is necessary, and need not proceed through the alerts sequentially.

1. Alert 1 — All available resources in use.



Circumstances:

• Balancing Authority, Reserve Sharing Group, or Load Serving Entity foresees or is experiencing conditions where all available resources are committed to meet firm load, firm transactions, and reserve commitments, and is concerned about sustaining its required Operating Reserves, and

• Non-firm wholesale energy sales (other than those that are recallable to meet reserve requirements) have been curtailed.

2. Alert 2 — Load management procedures in effect

.

Circumstances:

• Balancing Authority, Reserve Sharing Group, or Load Serving Entity is no longer able to provide its customers’ expected energy requirements, and is designated an Energy Deficient Entity.

• Energy Deficient Entity foresees or has implemented procedures up to, but excluding, interruption of firm load commitments. When time permits, these procedures may include, but are not limited to: o

Public appeals to reduce demand. o

Voltage reduction. o

Interruption of non-firm end use loads in accordance with applicable contracts 1 . o

Demand-side management. o

Utility load conservation measures.

During Alert 2, Reliability Coordinators, Balancing Authorities, and Energy Deficient Entities have the following responsibilities:

2.1

Notifying other Balancing Authorities and market participants

. The Energy Deficient Entity shall communicate its needs to other Balancing Authorities and market participants. Upon request from the Energy Deficient Entity, the respective Reliability Coordinator shall post the declaration of the alert level along with the name of the Energy Deficient Entity and, if applicable, its Balancing Authority on the NERC website.

2.2

Declaration period.

The Energy Deficient Entity shall update its Reliability Coordinator of the situation at a minimum of every hour until the Alert 2 is terminated. The Reliability Coordinator shall update the energy deficiency information posted on the NERC website as changes occur and pass this information on to the affected Reliability Coordinators, Balancing Authority, and

Transmission Providers

.

2.3

Sharing information on resource availability.

A Balancing Authority and market participants with available resources shall immediately contact the Energy Deficient Entity. This should include the possibility of selling non-firm (recallable) energy out of available Operating

Reserves. The Energy Deficient Entity shall notify the Reliability Coordinators of the results.

2.4

Evaluating and mitigating transmission limitations

. The Reliability Coordinators shall review all System Operating Limits (SOLs) and Interconnection Reliability Operating Limits

(IROLs) and transmission loading relief procedures in effect that may limit the Energy Deficient

Entity’s scheduling capabilities. Where appropriate, the Reliability Coordinators shall inform

1 For emergency, not economic, reasons.


Standard EOP-002-3.1 — Capacity and Energy Emergencies the Transmission Providers under their purview of the pending Energy Emergency and request that they increase their ATC by actions such as restoring transmission elements that are out of service, reconfiguring their transmission system, adjusting phase angle regulator tap positions, implementing emergency operating procedures, and reviewing generation redispatch options.

2.4.1

Notification of ATC adjustments

. Resulting increases in ATCs shall be simultaneously communicated to the Energy Deficient Entity and the market via posting on the appropriate OASIS websites by the Transmission Providers.

2.4.2

Availability of generation redispatch options

. Available generation redispatch options shall be immediately communicated to the Energy Deficient Entity by its Reliability

Coordinator.

2.4.3

Evaluating impact of current transmission loading relief events.

The Reliability

Coordinators shall evaluate the impact of any current transmission loading relief events on the ability to supply emergency assistance to the Energy Deficient Entity. This evaluation shall include analysis of system reliability and involve close communication among Reliability Coordinators and the Energy Deficient Entity.

2.4.4

Initiating inquiries on reevaluating SOLs and IROLs

. The Reliability Coordinators shall consult with the Balancing Authorities and Transmission Providers in their

Reliability Areas about the possibility of reevaluating and revising SOLs or IROLs.

2.5

Coordination of emergency responses.

The Reliability Coordinator shall communicate and coordinate the implementation of emergency operating responses.

2.6

Energy Deficient Entity actions.

Before declaring an Alert 3, the Energy Deficient Entity must make use of all available resources. This includes but is not limited to:

2.6.1

All available generation units are on line

. All generation capable of being on line in the time frame of the emergency is on line including quick-start and peaking units, regardless of cost.

2.6.2

Purchases made regardless of cost

. All firm and non-firm purchases have been made, regardless of cost.

2.6.3

Non-firm sales recalled and contractually interruptible loads and demand-side management curtailed

. All non-firm sales have been recalled, contractually interruptible retail loads curtailed, and demand-side management activated within provisions of the agreements.

2.6.4

Operating Reserves.

Operating reserves are being utilized such that the Energy

Deficient Entity is carrying reserves below the required minimum or has initiated emergency assistance through its operating reserve sharing program.

3.

Alert 3 — Firm load interruption imminent or in progress

Circumstances:

.

• Balancing Authority or Load Serving Entity foresees or has implemented firm load obligation interruption. The available energy to the Energy Deficient Entity, as determined from Alert 2, is only accessible with actions taken to increase transmission transfer capabilities.

3.1

Continue actions from Alert 2

. The Reliability Coordinators and the Energy Deficient Entity shall continue to take all actions initiated during Alert 2.

If the emergency has not already been posted on the NERC website (see paragraph 2.1), the respective Reliability Coordinators will, at this time, post on the website information concerning the emergency.



4.

3.2

Declaration Period.

The Energy Deficient Entity shall update its Reliability Coordinator of the situation at a minimum of every hour until the Alert 3 is terminated. The Reliability Coordinator shall update the energy deficiency information posted on the NERC website as changes occur and pass this information on to the affected Reliability Coordinators (via the RCIS), Balancing

Authorities, and Transmission Providers.

3.3

Use of Transmission short-time limits.

The Reliability Coordinators shall request the appropriate Transmission Providers within their Reliability Area to utilize available short-time transmission limits or other emergency operating procedures in order to increase transfer capabilities into the Energy Deficient Entity.

3.4

Reevaluating and revising SOLs and IROLs.

The Reliability Coordinator of the Energy

Deficient Entity shall evaluate the risks of revising SOLs and IROLs on the reliability of the overall transmission system. Reevaluation of SOLs and IROLs shall be coordinated with other

Reliability Coordinators and only with the agreement of the Balancing Authority or

Transmission Operator whose equipment would be affected. The resulting increases in transfer capabilities shall only be made available to the Energy Deficient Entity who has requested an

Energy Emergency Alert 3 condition. SOLs and IROLs shall only be revised as long as an Alert

3 condition exists or as allowed by the Balancing Authority or Transmission Operator whose equipment is at risk. The following are minimum requirements that must be met before SOLs or

IROLs are revised:

3.4.1

Energy Deficient Entity obligations.

The deficient Balancing Authority or Load

Serving Entity must agree that, upon notification from its Reliability Coordinator of the situation, it will immediately take whatever actions are necessary to mitigate any undue risk to the Interconnection. These actions may include load shedding.

3.4.2

Mitigation of cascading failures

. The Reliability Coordinator shall use its best efforts to ensure that revising SOLs or IROLs would not result in any cascading failures within the

Interconnection.

3.5

Returning to pre-emergency Operating Security Limits.

Whenever energy is made available to an Energy Deficient Entity such that the transmission systems can be returned to their preemergency SOLs or IROLs, the Energy Deficient Entity shall notify its respective Reliability

Coordinator and downgrade the alert.

3.5.1

Notification of other parties.

Upon notification from the Energy Deficient Entity that an alert has been downgraded, the Reliability Coordinator shall notify the affected

Reliability Coordinators (via the RCIS), Balancing Authorities, and Transmission

Providers that their systems can be returned to their normal limits.

3.6

Reporting.

Any time an Alert 3 is declared, the Energy Deficient Entity shall submit the report enclosed in this Attachment to its respective Reliability Coordinator within two business days of downgrading or termination of the alert. Upon receiving the report, the Reliability Coordinator shall review it for completeness and immediately forward it to the NERC staff for posting on the

NERC website. The Reliability Coordinator shall present this report to the Reliability

Coordinator Working Group at its next scheduled meeting.

Alert 0 - Termination.

When the Energy Deficient Entity believes it will be able to supply its customers’ energy requirements, it shall request of its Reliability Coordinator that the EEA be terminated.

4.1.

Notification.

The Reliability Coordinator shall notify all other Reliability Coordinators via the RCIS of the termination. The Reliability Coordinator shall also notify the


Standard EOP-002-3.1 — Capacity and Energy Emergencies affected Balancing Authorities and Transmission Operators. The Alert 0 shall also be posted on the NERC website if the original alert was so posted.

C. Energy Emergency Alert 3 Report

A Deficient Balancing Authority or Load Serving Entity declaring an Energy Emergency Alert 3 must complete the following report. Upon completion of this report, it is to be sent to the Reliability

Coordinator for review within two business days of the incident.

Requesting Balancing Authority:

Entity experiencing energy deficiency (if different from Balancing Authority):

Date/Time Implemented:

Date/Time Released:

Declared Deficiency Amount (MW):

Total energy supplied by other Balancing Authority during the Alert 3 period:

Conditions that precipitated call for “Energy Deficiency Alert 3”:

If “Energy Deficiency Alert 3” had not been called, would firm load be cut? If no, explain:

Explain what action was taken in each step to avoid calling for “Energy Deficiency Alert 3”:



1. All generation capable of being on line in the time frame of the energy deficiency was on line (including quick start and peaking units) without regard to cost.

2. All firm and nonfirm purchases were made regardless of cost.

3. All nonfirm sales were recalled within provisions of the sale agreement.

4. Interruptible load was curtailed where either advance notice restrictions were met or the interruptible load was considered part of spinning reserve.

5. Available load reduction programs were exercised (public appeals, voltage reductions, etc.).

6.

Comments:

Operating Reserves being utilized.



Reported By:

Title:

Organization:



Appendix QC-EOP-002-3.1

Provisions specific to the standard EOP-002-3.1 applicable in Québec


A. Introduction

1.

Title: Capacity and Energy Emergencies

2.

Number: EOP-002-3.1

3.


4.


5.

Effective Date:

5.1.

Adoption of the standard by the Régie de l'énergie: October 30, 2013

5.2.

Adoption of the appendix by the Régie de l'énergie: October 30, 2013

5.3.


B. Requirements


C. Measures


D. Compliance

1.


1.1.


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


1.3.

Compliance Monitoring and Enforcement Processes


1.4.

Data Retention


1.5.



Adopted by Régie de l’énergie (Decision D-2013-176) : October 30, 2013 Page QC-1 de 7




2.

Violation Severity Levels

Requirement Lower

R1 N/A N/A

Moderate

R2

R3

N/A

N/A

N/A

N/A

High

The Balancing Authority or

Reliability Coordinator failed to provide evidence that it has responsibility and clear decision-making authority to take whatever actions are needed to ensure the reliability of its respective area.

N/A

N/A

Severe

The responsible entity failed to exercise its authority to alleviate a Capacity or Energy

Emergency.

The Balancing Authority failed to implement its

Capacity or Energy

Emergency plan, when required and as appropriate, to reduce risks to the interconnected system.

The Balancing Authority experienced an operating

Capacity or Energy

Emergency and failed to communicate its current and future system conditions to its

Reliability Coordinator and its neighboring Balancing

Authorities.





Requirement

R4 N/A

Lower

N/A

Moderate

R5 N/A N/A

N/A

High

The Balancing Authority used the assistance provided by the

Interconnection’s frequency bias for more time than needed to implement corrective actions.

OR

The Balancing Authority unilaterally adjusted generation in an attempt to return Interconnection frequency to normal beyond that supplied through frequency bias action and

Interchange Schedule changes.

Severe

The Balancing Authority anticipating an operating

Capacity or Energy

Emergency failed to perform all actions necessary including bringing on all available generation postponing equipment maintenance, scheduling interchange purchases in advance, or preparing to reduce firm load.

The Balancing Authority used the assistance provided by the

Interconnection’s frequency bias for more time than needed to implement corrective actions.

AND

The Balancing Authority unilaterally adjusted generation in an attempt to return Interconnection frequency to normal beyond that supplied through frequency bias action and

Interchange Schedule changes.





Requirement

R6

R6.1

R6.2

R6.3

R6.4

R6.5

R6.6

N/A

N/A

N/A

N/A

N/A

N/A

N/A

Lower

N/A

N/A

N/A

N/A

N/A

N/A

N/A

Moderate High

The Balancing Authority was not able to comply with the

Control Performance and

Disturbance Control Standards and failed to immediately implement one (1) of the subrequirements R6.1, R6.2, R6.3,

R6.4, R6.5 or R6.6.

N/A

N/A

N/A

N/A

N/A

N/A

Severe



Disturbance Control Standards and failed to immediately implement one (1) or more of the sub-requirements R6.1,

R6.2, R6.3, R6.4, R6.5 or

R6.6.

OR



Disturbance Control Standards and did not immediately implement any remedies.

N/A

N/A

N/A

N/A

N/A

N/A





Requirement

R7

R7.1

R7.2

R8

N/A

N/A

N/A

N/A

Lower

N/A

Moderate High

The Balancing Authority exhausted the steps listed in

R6 or the steps listed in R6 could not be completed in sufficient time to resolve the emergency condition, and the

Balancing Authority failed to meet sub-requirement R7.1.

OR




N/A N/A

N/A N/A

A Reliability Coordinator had a Balancing Authority within its Reliability Coordinator area experiencing a potential or actual Energy Emergency and the Reliability Coordinator did not initiate an Energy

Emergency Alert Level 1 as detailed in Attachment 1-EOP-

002-0 "Energy Emergency

Alert Levels".

A Reliability Coordinator had a Balancing Authority within its Reliability Coordinator area experiencing a potential or actual Energy Emergency and the Reliability Coordinator did not initiate an Energy

Emergency Alert Level 2 or 3 as detailed in Attachment 1-

EOP-002-0 "Energy

Emergency Alert Levels".

Severe




AND




N/A

N/A

A Reliability Coordinator had a Balancing Authority within its Reliability Coordinator area experiencing a potential or actual Energy Emergency and the Reliability Coordinator did not act to mitigate the emergency condition by requesting emergency assistance when this was required.





Lower Moderate High Requirement

E9

E9.1

N/A

N/A

N/A

N/A

N/A

N/A

E9.2

E9.3

E9.4

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

Severe

N/A

For an expected elevation in transmission service priority from Priority 6 to Priority 7, the Load Serving Entity failed to request its Reliability

Coordinator initiate an Energy

Emergency Alert in accordance with Attachment 1

EOP-002-0.

The Reliability Coordinator failed to submit the report to

NERC for posting on the

NERC Website, noting the expected total MW that may have its transmission service priority changed.

The Reliability Coordinator failed to use EEA 1 to forecast the change of the priority of transmission service of an

Interchange Transaction on the system from Priority 6 to

Priority 7.

The Reliability Coordinator failed to use EEA 2 to announce the change of the priority of transmission service of an Interchange Transaction on the system from Priority 6 to Priority 7.







Attachment 1 EOP-002





Change Tracking

New


Standard FAC-010-2.1 — System Operating Limits Methodology for the Planning Horizon

A.

Introduction

1.

Title: System Operating Limits Methodology for the Planning Horizon

2.

Number:

FAC-010-2.1

3.

Purpose:

To ensure that System Operating Limits (SOLs) used in the reliable planning of the Bulk Electric System (BES) are determined based on an established methodology or methodologies.

4.

Applicability

5.

4.1.

Planning Authority

Effective Date:

April 19, 2010

B.

Requirements

R1.

The Planning Authority shall have a documented SOL Methodology for use in developing

SOLs within its Planning Authority Area. This SOL Methodology shall:

R1.1.

Be applicable for developing SOLs used in the planning horizon.

R1.2.

State that SOLs shall not exceed associated Facility Ratings.

R1.3.

Include a description of how to identify the subset of SOLs that qualify as IROLs.

R2.

The Planning Authority’s SOL Methodology shall include a requirement that SOLs provide

BES performance consistent with the following:

R2.1.

In the pre-contingency state and with all Facilities in service, the BES shall demonstrate transient, dynamic and voltage stability; all Facilities shall be within their

Facility Ratings and within their thermal, voltage and stability limits. In the determination of SOLs, the BES condition used shall reflect expected system conditions and shall reflect changes to system topology such as Facility outages.

R2.2.

Following the single Contingencies

1 identified in Requirement 2.2.1 through

Requirement 2.2.3, the system shall demonstrate transient, dynamic and voltage stability; all Facilities shall be operating within their Facility Ratings and within their thermal, voltage and stability limits; and Cascading or uncontrolled separation shall not occur.

R2.2.1.

Single line to ground or three-phase Fault (whichever is more severe), with

Normal Clearing, on any Faulted generator, line, transformer, or shunt device.

R2.2.2.

Loss of any generator, line, transformer, or shunt device without a Fault.

R2.2.3.

Single pole block, with Normal Clearing, in a monopolar or bipolar high voltage direct current system.

R2.3.

Starting with all Facilities in service, the system’s response to a single Contingency, may include any of the following:

R2.3.1.

Planned or controlled interruption of electric supply to radial customers or some local network customers connected to or supplied by the Faulted

Facility or by the affected area.

1 The Contingencies identified in R2.2.1 through R2.2.3 are the minimum contingencies that must be studied but are not necessarily the only Contingencies that should be studied.

Adopted by the Régie de l'énergie (decision D-2015-059): May 4, 2015 Page 1 of 9


R2.3.2.

System reconfiguration through manual or automatic control or protection actions.

R2.4.

To prepare for the next Contingency, system adjustments may be made, including changes to generation, uses of the transmission system, and the transmission system topology.

R2.5.

Starting with all Facilities in service and following any of the multiple Contingencies identified in Reliability Standard TPL-003 the system shall demonstrate transient, dynamic and voltage stability; all Facilities shall be operating within their Facility

Ratings and within their thermal, voltage and stability limits; and Cascading or uncontrolled separation shall not occur.

R2.6.

In determining the system’s response to any of the multiple Contingencies, identified in Reliability Standard TPL-003, in addition to the actions identified in R2.3.1 and

R2.3.2, the following shall be acceptable:

R2.6.1.

Planned or controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (non-recallable reserved) electric power

Transfers.

R3.

The Planning Authority’s methodology for determining SOLs, shall include, as a minimum, a description of the following, along with any reliability margins applied for each:

R3.1.

Study model (must include at least the entire Planning Authority Area as well as the critical modeling details from other Planning Authority Areas that would impact the

Facility or Facilities under study).

R3.2.

Selection of applicable Contingencies.

R3.3.

Level of detail of system models used to determine SOLs.

R3.4.

Allowed uses of Special Protection Systems or Remedial Action Plans.

R3.5.

Anticipated transmission system configuration, generation dispatch and Load level.

R3.6.

Criteria for determining when violating a SOL qualifies as an Interconnection

Reliability Operating Limit (IROL) and criteria for developing any associated IROL

T v

.

R4.

The Planning Authority shall issue its SOL Methodology, and any change to that methodology, to all of the following prior to the effectiveness of the change:

R4.1.

Each adjacent Planning Authority and each Planning Authority that indicated it has a reliability-related need for the methodology.

R4.2.

Each Reliability Coordinator and Transmission Operator that operates any portion of the Planning Authority’s Planning Authority Area.

R4.3.

Each Transmission Planner that works in the Planning Authority’s Planning Authority

Area.

R5.

If a recipient of the SOL Methodology provides documented technical comments on the methodology, the Planning Authority shall provide a documented response to that recipient within 45 calendar days of receipt of those comments. The response shall indicate whether a change will be made to the SOL Methodology and, if no change will be made to that SOL

Methodology, the reason why.

C.

Measures

M1.

The Planning Authority’s SOL Methodology shall address all of the items listed in

Requirement 1 through Requirement 3.

Adopted by the Régie de l'énergie (decision D-2015-059): May 4, 2015

Page 2 of 9


M2.

The Planning Authority shall have evidence it issued its SOL Methodology and any changes to that methodology, including the date they were issued, in accordance with Requirement 4.

M3.

If the recipient of the SOL Methodology provides documented comments on its technical review of that SOL methodology, the Planning Authority that distributed that SOL

Methodology shall have evidence that it provided a written response to that commenter within

45 calendar days of receipt of those comments in accordance with Requirement 5.

D.

Compliance

1.


1.1.


Regional Reliability Organization

1.2.


Each Planning Authority shall self-certify its compliance to the Compliance Monitor at least once every three years. New Planning Authorities shall demonstrate compliance through an on-site audit conducted by the Compliance Monitor within the first year that it commences operation. The Compliance Monitor shall also conduct an on-site audit once every nine years and an investigation upon complaint to assess performance.

The Performance-Reset Period shall be twelve months from the last non-compliance.

1.3.

Data Retention

The Planning Authority shall keep all superseded portions to its SOL Methodology for 12 months beyond the date of the change in that methodology and shall keep all documented comments on its SOL Methodology and associated responses for three years. In addition, entities found non-compliant shall keep information related to the non-compliance until found compliant.

The Compliance Monitor shall keep the last audit and all subsequent compliance records.

1.4.


The Planning Authority shall make the following available for inspection during an onsite audit by the Compliance Monitor or within 15 business days of a request as part of an investigation upon complaint:

1.4.1

SOL Methodology.

1.4.2

Documented comments provided by a recipient of the SOL Methodology on its technical review of a SOL Methodology, and the associated responses.

1.4.3

Superseded portions of its SOL Methodology that had been made within the past

12 months.

1.4.4

Evidence that the SOL Methodology and any changes to the methodology that occurred within the past 12 months were issued to all required entities.

2.

Levels of Non-Compliance for Western Interconnection: (To be replaced with VSLs once developed and approved by WECC)

2.1.

Level 1:

There shall be a level one non-compliance if either of the following conditions exists:

2.1.1

The SOL Methodology did not include a statement indicating that Facility

Ratings shall not be exceeded.

2.1.2

No evidence of responses to a recipient’s comments on the SOL Methodology.


Page 3 of 9


2.2.

Level 2:

The SOL Methodology did not include a requirement to address all of the elements in R2.1 through R2.3 and E1.

2.3.

Level 3:

There shall be a level three non-compliance if any of the following conditions exists:

2.3.1


Ratings shall not be exceeded and the methodology did not include evaluation of system response to one of the three types of single Contingencies identified in

R2.2.

2.3.2


Ratings shall not be exceeded and the methodology did not include evaluation of system response to two of the seven types of multiple Contingencies identified in

E1.1.

2.3.3

The System Operating Limits Methodology did not include a statement indicating that Facility Ratings shall not be exceeded and the methodology did not address two of the six required topics in R3.

2.4.

Level 4:

The SOL Methodology was not issued to all required entities in accordance with R4


Page 4 of 9


R2

R3

R4

3.

Violation Severity Levels:

R1


Not applicable.

The Planning Authority’s SOL

Methodology requires that SOLs are set to meet BES performance following single and multiple contingencies, but does not address the pre-contingency state (R2.1)

Moderate

The Planning Authority has a documented SOL Methodology for use in developing SOLs within its Planning Authority

Area, but it does not address

R1.2


Methodology requires that SOLs are set to meet BES performance in the precontingency state and following single contingencies, but does not address multiple contingencies. (R2.5-R2.6)

The Planning Authority has a methodology for determining

SOLs that includes a description for all but one of the following:

R3.1 through R3.6.

One or both of the following:

The Planning Authority issued its

SOL Methodology and changes


SOLs that includes a description for all but two of the following:

R3.1 through R3.6.

One of the following:



High



R1.3.


Methodology requires that SOLs are set to meet BES performance in the precontingency state and following multiple contingencies, but does not meet the performance for response to single contingencies. (R2.2 –R2.4)


SOLs that includes a description for all but three of the following:

R3.1 through R3.6.




Severe



R1.1.

OR

The Planning Authority has no documented SOL Methodology for use in developing SOLs within its Planning Authority

Area.


Methodology requires that SOLs are set to meet BES performance in the precontingency state but does not require that SOLs be set to meet the BES performance specified for response to single contingencies (R2.2-R2.4) and does not require that SOLs be set to meet the BES performance specified for response to multiple contingencies. (R2.5-R2.6)


SOLs that is missing a description of four or more of the following: R3.1 through R3.6.


The Planning Authority failed to issue its SOL Methodology and



Requirement Lower to that methodology to all but one of the required entities.

For a change in methodology, the changed methodology was provided up to 30 calendar days after the effectiveness of the change.

Moderate to that methodology to all but one of the required entities AND for a change in methodology, the changed methodology was provided 30 calendar days or more, but less than 60 calendar days after the effectiveness of the change.

OR


SOL Methodology and changes to that methodology to all but two of the required entities AND for a change in methodology, the changed methodology was provided up to 30 calendar days after the effectiveness of the change.

High to that methodology to all but one of the required entities AND for a change in methodology, the changed methodology was provided 60 calendar days or more, but less than 90 calendar days after the effectiveness of the change.

OR


SOL Methodology and changes to that methodology to all but two of the required entities AND for a change in methodology, the changed methodology was provided 30 calendar days or more, but less than 60 calendar days after the effectiveness of the change.

OR


SOL Methodology and changes to that methodology to all but three of the required entities

AND for a change in methodology, the changed methodology was provided up to

30 calendar days after the effectiveness of the change.

Severe changes to that methodology to more than three of the required entities.


SOL Methodology and changes to that methodology to all but one of the required entities AND for a change in methodology, the changed methodology was provided 90 calendar days or more after the effectiveness of the change.

OR


SOL Methodology and changes to that methodology to all but two of the required entities AND for a change in methodology, the changed methodology was provided 60 calendar days or more, but less than 90 calendar days after the effectiveness of the change.

OR


SOL Methodology and changes to that methodology to all but three of the required entities

AND for a change in methodology, the changed methodology was provided 30 calendar days or more, but less than 60 calendar days after the effectiveness of the change.


SOL Methodology and changes to that methodology to all but



R5

Requirement Lower Moderate

The Planning Authority received documented technical comments on its SOL Methodology and provided a complete response in a time period that was longer than 45 calendar days but less than 60 calendar days.

The Planning Authority received documented technical comments on its SOL Methodology and provided a complete response in a time period that was 60 calendar days or longer but less than 75 calendar days.

High

The Planning Authority received documented technical comments on its SOL Methodology and provided a complete response in a time period that was 75 calendar days or longer but less than 90 calendar days.

OR

The Planning Authority’s response to documented technical comments on its SOL

Methodology indicated that a change will not be made, but did not include an explanation of why the change will not be made.

Severe four of the required entities AND for a change in methodology, the changed methodology was provided up to 30 calendar days after the effectiveness of the change.

The Planning Authority received documented technical comments on its SOL Methodology and provided a complete response in a time period that was 90 calendar days or longer.

OR

The Planning Authority’s response to documented technical comments on its SOL

Methodology did not indicate whether a change will be made to the SOL Methodology.



E.

Regional Differences

1.

The following Interconnection-wide Regional Difference shall be applicable in the Western

Interconnection:

1.1.

As governed by the requirements of R2.5 and R2.6, starting with all Facilities in service, shall require the evaluation of the following multiple Facility Contingencies when establishing SOLs:

1.1.1

Simultaneous permanent phase to ground Faults on different phases of each of two adjacent transmission circuits on a multiple circuit tower, with Normal

Clearing. If multiple circuit towers are used only for station entrance and exit purposes, and if they do not exceed five towers at each station, then this condition is an acceptable risk and therefore can be excluded.

1.1.2

A permanent phase to ground Fault on any generator, transmission circuit, transformer, or bus section with Delayed Fault Clearing except for bus sectionalizing breakers or bus-tie breakers addressed in E1.1.7

1.1.3

Simultaneous permanent loss of both poles of a direct current bipolar Facility without an alternating current Fault.

1.1.4

The failure of a circuit breaker associated with a Special Protection System to operate when required following: the loss of any element without a Fault; or a permanent phase to ground Fault, with Normal Clearing, on any transmission circuit, transformer or bus section.

1.1.5

A non-three phase Fault with Normal Clearing on common mode Contingency of two adjacent circuits on separate towers unless the event frequency is determined to be less than one in thirty years.

1.1.6

A common mode outage of two generating units connected to the same switchyard, not otherwise addressed by FAC-010.

1.1.7

The loss of multiple bus sections as a result of failure or delayed clearing of a bus tie or bus sectionalizing breaker to clear a permanent Phase to Ground Fault.

1.2.

SOLs shall be established such that for multiple Facility Contingencies in E1.1.1 through

E1.1.5 operation within the SOL shall provide system performance consistent with the following:

1.2.1

All Facilities are operating within their applicable Post-Contingency thermal, frequency and voltage limits.

1.2.2

Cascading does not occur.

1.2.3

Uncontrolled separation of the system does not occur.

1.2.4

The system demonstrates transient, dynamic and voltage stability.

1.2.5

Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall security of the interconnected transmission systems.

1.2.6

Interruption of firm transfer, Load or system reconfiguration is permitted through manual or automatic control or protection actions.



1.2.7

To prepare for the next Contingency, system adjustments are permitted, including changes to generation, Load and the transmission system topology when determining limits.

1.3.


E1.1.7 operation within the SOL shall provide system performance consistent with the following with respect to impacts on other systems:

1.3.1


1.4.

The Western Interconnection may make changes (performance category adjustments) to the Contingencies required to be studied and/or the required responses to Contingencies for specific facilities based on actual system performance and robust design. Such changes will apply in determining SOLs.

Version History

Version

1

1

2

2

2

2.1

2.1

Date Action

November 1,

2006

November 1,

2006

June 24, 2008


Fixed typo. Removed the word “each” from the 1 st sentence of section D.1.3, Data

Retention.

Adopted by Board of Trustees; FERC Order

705

Changed the effective date to July 1, 2008

Changed “Cascading Outage” to

“Cascading”

Replaced Levels of Non-compliance with

Violation Severity Levels

January 22,

2010

Updated effective date and footer to April

29, 2009 based on the March 20, 2009

FERC Order

November 5,

2009

Adopted by the Board of Trustees — errata change Section E1.1 modified to reflect the renumbering of requirements R2.4 and R2.5 from FAC-010-1 to R2.5 and R2.6 in FAC-

010-2.

April 19, 2010 FERC Approved — errata change Section

E1.1 modified to reflect the renumbering of requirements R2.4 and R2.5 from FAC-010-

1 to R2.5 and R2.6 in FAC-010-2.

Change Tracking

New

01/11/07

Revised

Revised

Update

Errata

Errata



Appendix QC-FAC-010-2.1

Provisions specific to the standard FAC-010-2.1 applicable in Québec


A. Introduction

1.

Title: System Operating Limits Methodology for the Planning Horizon

2.

Number: FAC-010-2.1

3.


4.

Applicability:

Functions


Facilities

This standard only applies to the facilities of the Main Transmission System (RTP)

5.

Effective Date:

5.1.

Adoption of the standard by the Régie de l'énergie: May 4, 2015

5.2.

Adoption of the appendix by the Régie de l'énergie: May 4, 2015

5.3.


B. Requirements


C. Measures


D. Compliance

1.


1.1.



1.2.



1.3.

Data Retention


1.4.



2.

Levels of Non-Compliance for Western Interconnection


Adopted by Régie de l’énergie (Decision D-2015-059) : May 4, 2015 Page QC-1 of 2


Appendix QC-FAC-010-2.1

Provisions specific to the standard FAC-010-2.1 applicable in Québec

3.







0 May 4, 2015 New appendix

Change Tracking

New

Adopted by Régie de l’énergie (Decision D-2015-059) : May 4, 2015 Page QC-2 of 2

Standard FAC-011-2 — System Operating Limits Methodology for the Operations Horizon

A. Introduction

1.

Title: System Operating Limits Methodology for the Operations Horizon

2.

Number: FAC-011-2

3.

Purpose: To ensure that System Operating Limits (SOLs) used in the reliable operation of the Bulk Electric System (BES) are determined based on an established methodology or methodologies.

4.

Applicability

4.1.

Reliability Coordinator

5.

Effective Date:

B. Requirements

April 29, 2009

R1.

The Reliability Coordinator shall have a documented methodology for use in developing SOLs

(SOL Methodology) within its Reliability Coordinator Area. This SOL Methodology shall:

R1.1.

Be applicable for developing SOLs used in the operations horizon.

R1.2.

State that SOLs shall not exceed associated Facility Ratings.

R1.3.

Include a description of how to identify the subset of SOLs that qualify as IROLs.

R2.

The Reliability Coordinator’s SOL Methodology shall include a requirement that SOLs provide BES performance consistent with the following:

R2.1.

In the pre-contingency state, the BES shall demonstrate transient, dynamic and voltage stability; all Facilities shall be within their Facility Ratings and within their thermal, voltage and stability limits. In the determination of SOLs, the BES condition used shall reflect current or expected system conditions and shall reflect changes to system topology such as Facility outages.

R2.2.

Following the single Contingencies

1

identified in Requirement 2.2.1 through

Requirement 2.2.3, the system shall demonstrate transient, dynamic and voltage stability; all Facilities shall be operating within their Facility Ratings and within their thermal, voltage and stability limits; and Cascading or uncontrolled separation shall not occur.

R2.2.1.

Single line to ground or 3-phase Fault (whichever is more severe), with

Normal Clearing, on any Faulted generator, line, transformer, or shunt device.

R2.2.2.

Loss of any generator, line, transformer, or shunt device without a Fault.

R2.2.3.

Single pole block, with Normal Clearing, in a monopolar or bipolar high voltage direct current system.

R2.3.

In determining the system’s response to a single Contingency, the following shall be acceptable:

R2.3.1.

Planned or controlled interruption of electric supply to radial customers or some local network customers connected to or supplied by the Faulted

Facility or by the affected area.

1

The Contingencies identified in FAC-011 R2.2.1 through R2.2.3 are the minimum contingencies that must be studied but are not necessarily the only Contingencies that should be studied.

Adopted by Board of Trustees: June 24, 2008


Adopted by Régie de l'énergie (Decision 2015-059): May 4, 2015

Page 1 of 9


R2.3.2.

Interruption of other network customers, (a) only if the system has already been adjusted, or is being adjusted, following at least one prior outage, or

(b) if the real-time operating conditions are more adverse than anticipated in the corresponding studies

R2.3.3.

System reconfiguration through manual or automatic control or protection actions.

R2.4.

To prepare for the next Contingency, system adjustments may be made, including changes to generation, uses of the transmission system, and the transmission system topology.

R3.

The Reliability Coordinator’s methodology for determining SOLs, shall include, as a minimum, a description of the following, along with any reliability margins applied for each:

R3.1.

Study model (must include at least the entire Reliability Coordinator Area as well as the critical modeling details from other Reliability Coordinator Areas that would impact the Facility or Facilities under study.)

R3.2.

Selection of applicable Contingencies

R3.3.

A process for determining which of the stability limits associated with the list of multiple contingencies (provided by the Planning Authority in accordance with FAC-

014 Requirement 6) are applicable for use in the operating horizon given the actual or expected system conditions.

R3.3.1.

This process shall address the need to modify these limits, to modify the list of limits, and to modify the list of associated multiple contingencies.

R3.4.

Level of detail of system models used to determine SOLs.

R3.5.

Allowed uses of Special Protection Systems or Remedial Action Plans.

R3.6.

Anticipated transmission system configuration, generation dispatch and Load level

R3.7.

Criteria for determining when violating a SOL qualifies as an Interconnection

Reliability Operating Limit (IROL) and criteria for developing any associated IROL

T v

.

R4.

The Reliability Coordinator shall issue its SOL Methodology and any changes to that methodology, prior to the effectiveness of the Methodology or of a change to the Methodology, to all of the following:

R4.1.

Each adjacent Reliability Coordinator and each Reliability Coordinator that indicated it has a reliability-related need for the methodology.

R4.2.

Each Planning Authority and Transmission Planner that models any portion of the

Reliability Coordinator’s Reliability Coordinator Area.

R4.3.

Each Transmission Operator that operates in the Reliability Coordinator Area.

R5.

If a recipient of the SOL Methodology provides documented technical comments on the methodology, the Reliability Coordinator shall provide a documented response to that recipient within 45 calendar days of receipt of those comments. The response shall indicate whether a change will be made to the SOL Methodology and, if no change will be made to that SOL

Methodology, the reason why.

C. Measures




Page 2 of 9


M1.

The Reliability Coordinator’s SOL Methodology shall address all of the items listed in

Requirement 1 through Requirement 3.

M2.

The Reliability Coordinator shall have evidence it issued its SOL Methodology, and any changes to that methodology, including the date they were issued, in accordance with

Requirement 4.

M3.

If the recipient of the SOL Methodology provides documented comments on its technical review of that SOL methodology, the Reliability Coordinator that distributed that SOL

Methodology shall have evidence that it provided a written response to that commenter within

45 calendar days of receipt of those comments in accordance with Requirement 5

D. Compliance

1.


1.1.



1.2.


Each Reliability Coordinator shall self-certify its compliance to the Compliance Monitor at least once every three years. New Reliability Authorities shall demonstrate compliance through an on-site audit conducted by the Compliance Monitor within the first year that it commences operation. The Compliance Monitor shall also conduct an onsite audit once every nine years and an investigation upon complaint to assess performance.

The Performance-Reset Period shall be twelve months from the last non-compliance.

1.3.

Data Retention

The Reliability Coordinator shall keep all superseded portions to its SOL Methodology for 12 months beyond the date of the change in that methodology and shall keep all documented comments on its SOL Methodology and associated responses for three years.

In addition, entities found non-compliant shall keep information related to the noncompliance until found compliant.


1.4.


The Reliability Coordinator shall make the following available for inspection during an on-site audit by the Compliance Monitor or within 15 business days of a request as part of an investigation upon complaint:

1.4.1

SOL Methodology.

1.4.2

Documented comments provided by a recipient of the SOL Methodology on its technical review of a SOL Methodology, and the associated responses.

1.4.3

Superseded portions of its SOL Methodology that had been made within the past

12 months.

1.4.4

Evidence that the SOL Methodology and any changes to the methodology that occurred within the past 12 months were issued to all required entities.

2.

Levels of Non-Compliance for Western Interconnection: (To be replaced with VSLs once developed and approved by WECC)




Page 3 of 9


2.1.

Level 1: There shall be a level one non-compliance if either of the following conditions exists:

2.1.1


Ratings shall not be exceeded.

2.1.2

No evidence of responses to a recipient’s comments on the SOL Methodology

2.2.

Level 2: The SOL Methodology did not include a requirement to address all of the elements in R3.1, R3.2, R3.4 through R3.7 and E1.

2.3.

Level 3: There shall be a level three non-compliance if any of the following conditions exists:

2.3.1


Ratings shall not be exceeded and the methodology did not include evaluation of system response to one of the three types of single Contingencies identified in

R2.2.

2.3.2


Ratings shall not be exceeded and the methodology did not include evaluation of system response to two of the seven types of multiple Contingencies identified in

E1.1.

2.3.3

The System Operating Limits Methodology did not include a statement indicating that Facility Ratings shall not be exceeded and the methodology did not address two of the six required topics in R3.1, R3.2, R3.4 through R3.7.

2.4.

Level 4: The SOL Methodology was not issued to all required entities in accordance with R4.




Page 4 of 9


R2

R3

R4

3.


R1


Not applicable.

The Reliability Coordinator‘s

SOL Methodology requires that

SOLs are set to meet BES performance following single contingencies, but does not require that SOLs are set to meet BES performance in the pre-contingency state. (R2.1)

Moderate

The Reliability Coordinator has a documented SOL Methodology for use in developing SOLs within its Reliability Coordinator


R1.2

Not applicable.

The Reliability Coordinator has a methodology for determining

SOLs that includes a description for all but one of the following:

R3.1 through R3.7.

One or both of the following:

The Reliability Coordinator issued its SOL Methodology and changes to that methodology to all but one of the required entities.

For a change in methodology, the changed methodology was


SOLs that includes a description for all but two of the following:

R3.1 through R3.7.


The Reliability Coordinator issued its SOL Methodology and changes to that methodology to all but one of the required entities AND for a change in methodology, the changed methodology was provided 30



R1.3.

High

The Reliability Coordinator‘s

SOL Methodology requires that

SOLs are set to meet BES performance in the precontingency state, but does not require that SOLs are set to meet BES performance following single contingencies. (R2.2 –

R2.4)


SOLs that includes a description for all but three of the following:

R3.1 through R3.7.


The Reliability Coordinator issued its SOL Methodology and changes to that methodology to all but one of the required entities AND for a change in methodology, the changed methodology was provided 60

Severe



R1.1.

OR

The Reliability Coordinator has no documented SOL

Methodology for use in developing SOLs within its

Reliability Coordinator Area.

The Reliability Coordinator’s

SOL Methodology does not require that SOLs are set to meet BES performance in the pre-contingency state and does not require that SOLs are set to meet BES performance following single contingencies. (R2.1 through R2.4)


SOLs that is missing a description of three or more of the following: R3.1 through R3.7.


The Reliability Coordinator failed to issue its SOL Methodology and changes to that methodology to more than three of the required entities.

The Reliability Coordinator issued its SOL Methodology and




Page 5 of 9


Requirement Lower provided up to 30 calendar days after the effectiveness of the change.

Moderate calendar days or more, but less than 60 calendar days after the effectiveness of the change.

OR

The Reliability Coordinator issued its SOL Methodology and changes to that methodology to all but two of the required entities

AND for a change in methodology, the changed methodology was provided up to


High calendar days or more, but less than 90 calendar days after the effectiveness of the change.

OR



OR

The Reliability Coordinator issued its SOL Methodology and changes to that methodology to all but three of the required entities AND for a change in methodology, the changed methodology was provided up to


Severe changes to that methodology to all but one of the required entities AND for a change in methodology, the changed methodology was provided 90 calendar days or more after the effectiveness of the change.

OR



OR

The Reliability Coordinator issued its SOL Methodology and changes to that methodology to all but three of the required entities AND for a change in methodology, the changed methodology was provided 30 calendar days or more, but less than 60 calendar days after the effectiveness of the change.

OR

The Reliability Coordinator issued its SOL Methodology and changes to that methodology to all but four of the required entities AND for a change in methodology, the changed methodology was provided up to




Page 6 of 9


R5


The Reliability Coordinator received documented technical comments on its SOL

Methodology and provided a complete response in a time period that was longer than 45 calendar days but less than 60 calendar days.

Moderate High


Methodology and provided a complete response in a time period that was 60 calendar days or longer but less than 75 calendar days.


Methodology and provided a complete response in a time period that was 75 calendar days or longer but less than 90 calendar days.

OR

The Reliability Coordinator’s response to documented technical comments on its SOL

Methodology indicated that a change will not be made, but did not include an explanation of why the change will not be made.

Severe



Methodology and provided a complete response in a time period that was 90 calendar days or longer.

OR

The Reliability Coordinator’s response to documented technical comments on its SOL

Methodology did not indicate whether a change will be made to the SOL Methodology.




Page 7 of 9



1.

The following Interconnection-wide Regional Difference shall be applicable in the Western

Interconnection:

1.1.

As governed by the requirements of R3.3, starting with all Facilities in service, shall require the evaluation of the following multiple Facility Contingencies when establishing

SOLs:

1.1.1

Simultaneous permanent phase to ground Faults on different phases of each of two adjacent transmission circuits on a multiple circuit tower, with Normal

Clearing. If multiple circuit towers are used only for station entrance and exit purposes, and if they do not exceed five towers at each station, then this condition is an acceptable risk and therefore can be excluded.

1.1.2

A permanent phase to ground Fault on any generator, transmission circuit, transformer, or bus section with Delayed Fault Clearing except for bus sectionalizing breakers or bus-tie breakers addressed in E1.1.7

1.1.3

Simultaneous permanent loss of both poles of a direct current bipolar Facility without an alternating current Fault.

1.1.4

The failure of a circuit breaker associated with a Special Protection System to operate when required following: the loss of any element without a Fault; or a permanent phase to ground Fault, with Normal Clearing, on any transmission circuit, transformer or bus section.

1.1.5

A non-three phase Fault with Normal Clearing on common mode Contingency of two adjacent circuits on separate towers unless the event frequency is determined to be less than one in thirty years.

1.1.6

A common mode outage of two generating units connected to the same switchyard, not otherwise addressed by FAC-011.

1.1.7

The loss of multiple bus sections as a result of failure or delayed clearing of a bus tie or bus sectionalizing breaker to clear a permanent Phase to Ground Fault.

1.2.


E1.1.5 operation within the SOL shall provide system performance consistent with the following:

1.2.1

All Facilities are operating within their applicable Post-Contingency thermal, frequency and voltage limits.

1.2.2


1.2.3

Uncontrolled separation of the system does not occur.

1.2.4

The system demonstrates transient, dynamic and voltage stability.

1.2.5

Depending on system design and expected system impacts, the controlled interruption of electric supply to customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall security of the interconnected transmission systems.

1.2.6

Interruption of firm transfer, Load or system reconfiguration is permitted through manual or automatic control or protection actions.



Page 8 of 9


1.2.7

To prepare for the next Contingency, system adjustments are permitted, including changes to generation, Load and the transmission system topology when determining limits.

1.3.


E1.1.7 operation within the SOL shall provide system performance consistent with the following with respect to impacts on other systems:

1.3.1


1.4.

The Western Interconnection may make changes (performance category adjustments) to the Contingencies required to be studied and/or the required responses to Contingencies for specific facilities based on actual system performance and robust design. Such changes will apply in determining SOLs.

Version History

Version Date Action Change Tracking

New

2

2006

2 June 24, 2008

2010

Changed the effective date to October 1,

2008

Changed “Cascading Outage” to

“Cascading”



Corrected footnote 1 to reference FAC-011 rather than FAC-010

Adopted by Board of Trustees: FERC Order

705

Revised

Revised

Update


FERC Order




Page 9 of 9


Appendix QC-FAC-011-2

Provisions specific to the standard FAC-011-2 applicable in Québec


A. Introduction

1.

Title: System Operating Limits Methodology for the Operations Horizon

2.

Number: FAC-011-2

3.


4.

Applicability:

Functions


Facilities

This standard only applies to the facilities of the Main Transmission System (RTP).

5.

Effective Date:

5.1.


5.2.


5.3.


B. Requirements


C. Measures


D. Compliance

1.


1.1.



1.2.



1.3.

Data Retention


1.4.



2.



Adopted by the Régie de l’énergie (Décision D-2015-059): May 4, 2015 Page QC-1 of 2




3.


All occurrences of the term “BES” are replaced by “RTP”.






Change Tracking

New

Adopted by the Régie de l’énergie (Décision D-2015-059): May 4, 2015 Page QC-2 of 2

Standard FAC-014-2 — Establish and Communicate System Operating Limits

A. Introduction

1.

Title: Establish and Communicate System Operating Limits

2.

Number: FAC-014-2

3.

Purpose: To ensure that System Operating Limits (SOLs) used in the reliable planning and operation of the Bulk Electric System (BES) are determined based on an established methodology or methodologies.

4.

Applicability

4.1.

Reliability Coordinator

4.2.

Planning Authority

4.3.

Transmission Planner

4.4.

Transmission Operator

5.

Effective Date: 2009

B. Requirements

R1.

The Reliability Coordinator shall ensure that SOLs, including Interconnection Reliability

Operating Limits (IROLs), for its Reliability Coordinator Area are established and that the

SOLs (including Interconnection Reliability Operating Limits) are consistent with its SOL

Methodology.

R2.

The Transmission Operator shall establish SOLs (as directed by its Reliability Coordinator) for its portion of the Reliability Coordinator Area that are consistent with its Reliability

Coordinator’s SOL Methodology.

R3.

The Planning Authority shall establish SOLs, including IROLs, for its Planning Authority Area that are consistent with its SOL Methodology.

R4.

The Transmission Planner shall establish SOLs, including IROLs, for its Transmission

Planning Area that are consistent with its Planning Authority’s SOL Methodology.

R5.

The Reliability Coordinator, Planning Authority and Transmission Planner shall each provide its SOLs and IROLs to those entities that have a reliability-related need for those limits and provide a written request that includes a schedule for delivery of those limits as follows:

R5.1.

The Reliability Coordinator shall provide its SOLs (including the subset of SOLs that are IROLs) to adjacent Reliability Coordinators and Reliability Coordinators who indicate a reliability-related need for those limits, and to the Transmission Operators,

Transmission Planners, Transmission Service Providers and Planning Authorities within its Reliability Coordinator Area. For each IROL, the Reliability Coordinator shall provide the following supporting information:

R5.1.1.

Identification and status of the associated Facility (or group of Facilities) that is (are) critical to the derivation of the IROL.

R5.1.2.

The value of the IROL and its associated T v

.

R5.1.3.

The associated Contingency(ies).

R5.1.4.

The type of limitation represented by the IROL (e.g., voltage collapse, angular stability).



Adopted by the Régie de l'énergie (Décision D-2013-176): October 30, 2013

Page 1 of 6


R5.2.

The Transmission Operator shall provide any SOLs it developed to its Reliability

Coordinator and to the Transmission Service Providers that share its portion of the

Reliability Coordinator Area.

R5.3.

The Planning Authority shall provide its SOLs (including the subset of SOLs that are

IROLs) to adjacent Planning Authorities, and to Transmission Planners, Transmission

Service Providers, Transmission Operators and Reliability Coordinators that work within its Planning Authority Area.

R5.4.

The Transmission Planner shall provide its SOLs (including the subset of SOLs that are IROLs) to its Planning Authority, Reliability Coordinators, Transmission

Operators, and Transmission Service Providers that work within its Transmission

Planning Area and to adjacent Transmission Planners.

R6.

The Planning Authority shall identify the subset of multiple contingencies (if any), from

Reliability Standard TPL-003 which result in stability limits.

R6.1.

The Planning Authority shall provide this list of multiple contingencies and the associated stability limits to the Reliability Coordinators that monitor the facilities associated with these contingencies and limits.

R6.2.

If the Planning Authority does not identify any stability-related multiple contingencies, the Planning Authority shall so notify the Reliability Coordinator.

C. Measures

M1.

The Reliability Coordinator, Planning Authority, Transmission Operator, and Transmission

Planner shall each be able to demonstrate that it developed its SOLs (including the subset of

SOLs that are IROLs) consistent with the applicable SOL Methodology in accordance with

Requirements 1 through 4.

M2.

The Reliability Coordinator, Planning Authority, Transmission Operator, and Transmission

Planner shall each have evidence that its SOLs (including the subset of SOLs that are IROLs) were supplied in accordance with schedules supplied by the requestors of such SOLs as specified in Requirement 5.

M3.

The Planning Authority shall have evidence it identified a list of multiple contingencies (if any) and their associated stability limits and provided the list and the limits to its Reliability

Coordinators in accordance with Requirement 6.

D. Compliance

1.

Compliance Monitoring Process

1.1.



1.2.


The Reliability Coordinator, Planning Authority, Transmission Operator, and

Transmission Planner shall each verify compliance through self-certification submitted to its Compliance Monitor annually. The Compliance Monitor may conduct a targeted audit once in each calendar year (January – December) and an investigation upon a complaint to assess performance.

The Performance-Reset Period shall be twelve months from the last finding of noncompliance.

1.3.

Data Retention




Page 2 of 6



Transmission Planner shall each keep documentation for 12 months. In addition, entities found non-compliant shall keep information related to non-compliance until found compliant.


1.4.



Transmission Planner shall each make the following available for inspection during a targeted audit by the Compliance Monitor or within 15 business days of a request as part of an investigation upon complaint:

1.4.1

SOL Methodology(ies)

1.4.2

SOLs, including the subset of SOLs that are IROLs and the IROLs supporting information

1.4.3

Evidence that SOLs were distributed

1.4.4

Evidence that a list of stability-related multiple contingencies and their associated limits were distributed

1.4.5

Distribution schedules provided by entities that requested SOLs




Page 3 of 6


2.


Requirement

R1

R2

R3

R4

R5

Lower

There are SOLs, for the

Reliability Coordinator Area, but from 1% up to but less than 25% of these SOLs are inconsistent with the Reliability Coordinator’s

SOL Methodology. (R1)

The Transmission Operator has established SOLs for its portion of the Reliability Coordinator

Area, but from 1% up to but less than 25% of these SOLs are inconsistent with the Reliability


(R2)

There are SOLs, for the Planning

Coordinator Area, but from 1% up to, but less than, 25% of these

SOLs are inconsistent with the

Planning Coordinator’s SOL

Methodology. (R3)

The Transmission Planner has established SOLs for its portion of the Planning Coordinator Area, but up to 25% of these SOLs are inconsistent with the Planning


(R4)

The responsible entity provided its SOLs (including the subset of

SOLs that are IROLs) to all the requesting entities but missed meeting one or more of the schedules by less than 15

Moderate


Reliability Coordinator Area, but

25% or more, but less than 50% of these SOLs are inconsistent with the Reliability Coordinator’s



Area, but 25% or more, but less than 50% of these SOLs are inconsistent with the Reliability


(R2)


Coordinator Area, but 25% or more, but less than 50% of these



Methodology. (R3)

The Transmission Planner has established SOLs for its portion of the Planning Coordinator Area, but 25% or more, but less than

50% of these SOLs are inconsistent with the Planning


(R4)



SOLs that are IROLs) to all but one of the requesting entities within the schedules provided.

High


Reliability Coordinator Area, but

50% or more, but less than 75% of these SOLs are inconsistent with the Reliability Coordinator’s



Area, but 50% or more, but less than 75% of these SOLs are inconsistent with the Reliability


(R2)

There are SOLs for the Planning

Coordinator Area, but 50% or more, but less than 75% of these



Methodology. (R3)

The Transmission Planner has established SOLs for its portion of the Reliability Coordinator

Area, but 50% or more, but less than 75% of these SOLs are inconsistent with the Planning


(R4)



SOLs that are IROLs) to all but two of the requesting entities within the schedules provided.

Severe

There are SOLs for the Reliability

Coordinator Area, but 75% or more of these SOLs are inconsistent with the Reliability


(R1)


Area, but 75% or more of these


Reliability Coordinator’s SOL

Methodology. (R2)


Coordinator Area, but 75% or more of these SOLs are inconsistent with the Planning


(R3)

The Transmission Planner has established SOLs for its portion of the Planning Coordinator Area, but 75% or more of these SOLs are inconsistent with the Planning


(R4)


The responsible entity failed to provide its SOLs (including the subset of SOLs that are IROLs) to more than two of the requesting entities within 45




Page 4 of 6


Requirement

R6

Lower calendar days. (R5)

The Planning Authority failed to notify the Reliability Coordinator in accordance with R6.2

Moderate

(R5)

Or

The responsible entity provided its SOLs to all the requesting entities but missed meeting one or more of the schedules for 15 or more but less than 30 calendar days. (R5)

OR

The supporting information provided with the IROLs does not address 5.1.4

Not applicable.

High

(R5)

Or

The responsible entity provided its SOLs to all the requesting entities but missed meeting one or more of the schedules for 30 or more but less than 45 calendar days. (R5)

OR

The supporting information provided with the IROLs does not address 5.1.3

The Planning Authority identified the subset of multiple contingencies which result in stability limits but did not provide the list of multiple contingencies and associated limits to one

Reliability Coordinator that monitors the Facilities associated with these limits. (R6.1)

Severe calendar days of the associated schedules. (R5)

OR

The supporting information provided with the IROLs does not address 5.1.1 and 5.1.2.

The Planning Authority did not identify the subset of multiple contingencies which result in stability limits. (R6)

OR

The Planning Authority identified the subset of multiple contingencies which result in stability limits but did not provide the list of multiple contingencies and associated limits to more than one Reliability Coordinator that monitors the Facilities associated with these limits.

(R6.1)




Page 5 of 6



None identified.

Version History

Version Date

2

2

2006

June 24, 2008

2010

Action Change Tracking

New

Changed the effective date to January 1,

2009



Revised

Adopted by Board of Trustees: FERC Order Revised

Update


FERC Order




Page 6 of 6





A. Introduction

1.

Title: Establish and Communicate System Operating Limits

2.

Number: FAC-014-2

3.


4.

Applicability:

Functions


Facilities


5.

Effective Date:

5.1.

Adoption of the standard by the Régie de l'énergie: October 30, 2013

5.2.

Adoption of the appendix by the Régie de l'énergie: October 30, 2013

5.3.


B. Requirements


C. Measures


D. Compliance

1.


1.1.



1.2.



1.3.

Data Retention


1.4.



2.



Adopted by the Régie de l’énergie (Décision D-2013-176): October 30, 2013 Page QC-1 of 2









Change Tracking

New

Adopted by the Régie de l’énergie (Décision D-2013-176): October 30, 2013 Page QC-2 of 2

Standard IRO-002-2 — Reliability Coordination — Facilities

A.

Introduction

1.

Title:

2.

3.

Reliability Coordination — Facilities

Number:

IRO 002-2

Purpose:

Reliability Coordinators need information, tools and other capabilities to perform their responsibilities.

4.

Applicability

4.1.


5.

Proposed Effective Date:

In those jurisdictions where no regulatory approval is required, the standard shall become effective on the latter of either April 1, 2009 or the first day of the first calendar quarter, three months after Board of Trustee adoption.

In those jurisdictions where regulatory approval is required, the standard shall become effective on the latter of either April 1, 2009 or the first day of the first calendar quarter, three months after applicable regulatory approval.

B.

Requirements

R1.

Each Reliability Coordinator shall have adequate communications facilities (voice and data links) to appropriate entities within its Reliability Coordinator Area. These communications facilities shall be staffed and available to act in addressing a real-time emergency condition.

R2.

Each Reliability Coordinator — or its Transmission Operators and Balancing Authorities — shall provide, or arrange provisions for, data exchange to other Reliability Coordinators or

Transmission Operators and Balancing Authorities via a secure network.

R3.

Each Reliability Coordinator shall have multi-directional communications capabilities with its

Transmission Operators and Balancing Authorities, and with neighboring Reliability

Coordinators, for both voice and data exchange as required to meet reliability needs of the

Interconnection.

R4.

Each Reliability Coordinator shall have detailed real-time monitoring capability of its

Reliability Coordinator Area and sufficient monitoring capability of its surrounding Reliability

Coordinator Areas to ensure that potential or actual System Operating Limit or Interconnection

Reliability Operating Limit violations are identified. Each Reliability Coordinator shall have monitoring systems that provide information that can be easily understood and interpreted by the Reliability Coordinator’s operating personnel, giving particular emphasis to alarm management and awareness systems, automated data transfers, and synchronized information systems, over a redundant and highly reliable infrastructure.

R5.

Each Reliability Coordinator shall monitor Bulk Electric System elements (generators, transmission lines, buses, transformers, breakers, etc.) that could result in SOL or IROL violations within its Reliability Coordinator Area. Each Reliability Coordinator shall monitor both real and reactive power system flows, and operating reserves, and the status of Bulk

Electric System elements that are or could be critical to SOLs and IROLs and system restoration requirements within its Reliability Coordinator Area.

R6.

Each Reliability Coordinator shall have adequate analysis tools such as state estimation, pre- and post-contingency analysis capabilities (thermal, stability, and voltage), and wide-area overview displays.

Adopted by the Régie de l'énergie (decision D-2015-059): May 4, 2015 Page 1 of 8


R7.

Each Reliability Coordinator shall continuously monitor its Reliability Coordinator Area. Each

Reliability Coordinator shall have provisions for backup facilities that shall be exercised if the main monitoring system is unavailable. Each Reliability Coordinator shall ensure SOL and

IROL monitoring and derivations continue if the main monitoring system is unavailable.

R8.

Each Reliability Coordinator shall control its Reliability Coordinator analysis tools, including approvals for planned maintenance. Each Reliability Coordinator shall have procedures in place to mitigate the effects of analysis tool outages.

C.

Measures

M1.

Each Reliability Coordinator shall have and provide upon request evidence that could include, but is not limited to, a document that lists its voice communications facilities with

Transmission Operators, Balancing Authorities and Generator Operators within its Reliability

Coordinator Area and with neighboring Reliability Coordinators, that will be used to confirm that it has communication facilities in accordance with Requirements 1 and 3.

M2.

Each Reliability Coordinator shall have and provide upon request evidence that could include, but is not limited to, a data-link facility description document, computer print-out, trainingdocument, or other equivalent evidence that will be used to confirm that it has data links with entities within its Reliability Coordinator Area and with neighboring Reliability Coordinators, as specified in Requirements 1 and 3.

M3.

Each Reliability Coordinator shall have and provide upon request evidence that could include, but is not limited to, Energy Management System description documents, computer printouts,

SCADA data collection system communications performance or equivalent evidence to demonstrate that it has real-time monitoring capability of its Reliability Coordinator Area and monitoring capability of its surrounding Reliability Coordinator Areas to identify potential or actual System Operating Limit or Interconnection Reliability Operating Limit violations.

M4.

Each Reliability Coordinator shall have and provide upon request evidence that could include, but is not limited to, documentation from suppliers, operating and planning staff training documents, examples of studies, or other equivalent evidence to show that it has analysis tools in accordance with Requirement 6.

M5.

Each Reliability Coordinator shall provide evidence such as equipment specifications, operating procedures, staff records of their involvement in training, or other equivalent evidence to show that it has a backup monitoring facility that can be used to identify and monitor SOLs and IROLs. (Requirement 7)

M6.

Each Reliability Coordinator shall have and provide upon request evidence that could include, but is not limited to, a documented procedure or equivalent evidence that will be used to confirm that the Reliability Coordinator has the authority to veto planned outages to analysis tools, including final approvals for planned maintenance as specified in Requirement 8 Part 1.

M7.

Each Reliability Coordinator shall have and provide upon request its current procedures used to mitigate the effects of analysis tool outages as specified in Requirement 8 Part 2.

D.

Compliance

1.


1.1.


Regional Reliability Organizations shall be responsible for compliance.

Monitoring.



1.2.



-


-


-


-



1.3.

Data Retention

Each Reliability Coordinator shall have current in-force documents used to show compliance with Measures 1 through 7.


Evidence used as part of a triggered investigation shall be retained by the entity being investigated for one year from the date that the investigation is closed, as determined by the Compliance Monitor,


1.4.


None.



2.


Requirement

R1

Lower

The Reliability Coordinator has demonstrated communication facilities for both voice and data exist to all appropriate entities and that they are staffed and available but they are less than adequate.

R2

R3

N/A

N/A

Moderate

The Reliability Coordinator has failed to demonstrate that is has:

1) Voice communication links with one appropriate entity or

2) Data links with one appropriate entity.

High


1) Voice communication links with two appropriate entities or

2) Data links with two appropriate entities.

The Reliability Coordinator or designated Transmission

Operator and Balancing

Authority has failed to demonstrate it provided or arranged provision for the exchange of data with one of the other Reliability

Coordinators or Transmission

Operators and Balancing

Authorities.

The Reliability Coordinator has failed to demonstrate multi-directional communication capabilities to one of the Transmission


Authorities in its Reliability

Coordinator Area and with neighboring Reliability

Coordinators.



Authority has failed to demonstrate it provided or arranged provision for the exchange of data with two of the other Reliability



Authorities.

The Reliability Coordinator has failed to demonstrate multi-directional communication capabilities to two or more of the

Transmission Operators and

Balancing Authorities in its

Reliability Coordinator Area and with neighboring


Severe


1) Voice communication links with more than two appropriate entities or

2) Data links with more than two appropriate entities or

3) Communication facilities are not staffed or

4) Communication facilities are not ready.



Authority has failed to demonstrate it provided or arranged provision for the exchange of data with three of the other Reliability



Authorities.

The Reliability Coordinator has failed to demonstrate multi-directional communication capabilities to all of the Transmission


Authorities in its Reliability

Coordinator Area and with all neighboring Reliability

Coordinators.



Requirement

R4

R5

Lower

The Reliability Coordinator's monitoring systems provide information in a way that is not easily understood and interpreted by the Reliability

Coordinator's operating personnel or particular emphasis was not given to alarm management and awareness systems, automated data transfers and synchronized information systems.

The Reliability Coordinator failed to monitor:

1) the status, real power flow or reactive power flow of

Bulk Electric System elements that could result in one SOL violations or

2) or operating reserves for a small portion of the

Reliability Authority Area.

Moderate

The Reliability Coordinator has failed to demonstrate that is has detailed real-time monitoring capabilities in its

Reliability Coordinator Area and sufficient monitoring capabilities of its surrounding

Reliability Coordinator Areas to ensure that one potential or actual SOL or IROL violation is not identified.

High



Reliability Coordinator Areas to ensure that two or more potential and actual SOL and

IROL violations are not identified.



Bulk Electric System elements critical to assessing one IROL or to system restoration,


Bulk Electric System elements that could result in multiple SOL violations, or

3) operating reserves.



Bulk Electric System elements critical to assessing two or more IROLs; or one

IROL and to system restoration,


Bulk Electric System elements that could result in multiple SOL violations and operating reserves, or


Bulk Electric System elements critical to assessing one IROL or system restoration and operating reserves.

Severe



Reliability Coordinator Areas to ensure that all potential and actual SOL and IROL violations are identified.



Bulk Electric System elements critical to assessing all IROLs and to system restoration, or


Bulk Electric System elements critical to assessing all SOL violations and operating reserves.



Requirement

R6

R7

Lower

The Reliability Coordinator failed to demonstrate that it has:

1) analysis tools capable of assessing all pre-contingency flows,

2) analysis tools capable of assessing all postcontingency flows, or

3) all necessary wide-area overview displays exist.

The Reliability Coordinator failed to demonstrate that:

1) it or a delegated entity monitored SOLs when the main monitoring system was unavailable or

2) it has provisions to monitor

SOLs when the main monitoring system is not available.

Moderate


1) analysis tools capable of assessing the majority of precontingency flows,

2) analysis tools capable of assessing the majority of post-contingency flows, or

3) the majority of necessary wide-area overview displays exist.


1) it or a delegated entity monitored one IROL when the main monitoring system was unavailable or

2) it has provisions to monitor one IROL when the main monitoring system is not available.

High


1) analysis tools capable of assessing a minority of precontingency flows,

2) analysis tools capable of assessing a minority of postcontingency flows, or

3) a minority of necessary wide-area overview displays exist.


1) it or a delegated entity monitored two or more

IROLs when the main monitoring system was unavailable,

2) it or a delegated entity monitored SOLs and one

IROL when the main monitoring system was unavailable

3) it has provisions to monitor two or more IROLs when the main monitoring system is not available, or

4) it has provisions to monitor

SOLs and one IROL when the main monitoring system was unavailable.

Severe


1) analysis tools capable of assessing any precontingency flows,

2) analysis tools capable of assessing any postcontingency flows, or

3) any necessary wide-area overview displays exist.

R9.

The Reliability

Coordinator failed to demonstrate that it continuously monitored its

Reliability Authority

Area.



Requirement

R8

Lower

Reliability Coordinator has approval rights for planned maintenance outages of analysis tools but does not have approval rights for work on analysis tools that creates a greater risk of an unplanned outage of the tools.

Moderate

Reliability Coordinator has approval rights for planned maintenance but does not have plans to mitigate the effects of outages of the analysis tools.

High

Reliability Coordinator has approval rights for planned maintenance but does not have plans to mitigate the effects of outages of the analysis tools and does not have approval rights for work on analysis tools that creates a greater risk of an unplanned outage of the tools.

Severe

Reliability Coordinator approval is not required for planned maintenance.



E.

Regional Variances

None identified.

Version History

Version

0

Date Action


0

1

2

August 8, 2005 Removed “Proposed” from Effective

Date

November 1,

2006


Deleted R2, M3 and associated compliance elements

Replaced Levels of Non-compliance with the Feb 28, BOT approved

Violation Severity Levels (VSLs)

Corrected typographical errors in BOT approved version of VSLs

2

2

October 17,

2008

March 17,

2011


Order issued by FERC approving IRO-

002-2 (approval effective 5/23/11)

Change Tracking

New

Errata

Revised

Revised


Standard IRO-002-2 — Reliability Coordination – Facilities

Appendix QC-IRO-002-2

Provisions specific to the standard IRO-002-2 applicable in Québec


A. Introduction

1.

Title: Reliability Coordination – Facilities

2.

Number: IRO-002-2

3.


4.

Applicability:

Functions


Facilities


5.

Effective Date:

5.1.


5.2.

Adoption of the appendix by the Régie de l’énergie: May 4, 2015

5.3.


B. Requirements

Specific provisions regarding generation facilities for industrial use applicable to requirement

R5:

The Reliability Coordinator is not required to perform the monitoring specified in requirement R5 for generation facilities that are mainly used to supply industrial loads. However, it shall perform that monitoring at the connection points of the system of the entities owning generation facilities for industrial use.

C. Measures


D. Compliance

1.


1.1.



1.2.



1.3.

Data Retention


Adopted by the Régie de l’énergie (Décision D-2015-059) : May 4, 2015 Page QC-1 de 2

Standard IRO-002-2 — Reliability Coordination – Facilities



1.4.



2.








Change Tracking

New


Standard IRO-003-2 — Reliability Coordination — Wide-Area View

A. Introduction

1.

2.

3.

Number: IRO-003-2

Purpose: The Reliability Coordinator must have a wide-area view of its own

Reliability Coordinator Area and that of neighboring Reliability Coordinators.

4.

5.

Applicability

4.1.


Effective Date:

B. Requirements

January 1, 2007

R1.

Each Reliability Coordinator shall monitor all Bulk Electric System facilities, which may include sub-transmission information, within its Reliability Coordinator Area and adjacent Reliability Coordinator Areas, as necessary to ensure that, at any time, regardless of prior planned or unplanned events, the Reliability Coordinator is able to determine any potential System Operating Limit and Interconnection Reliability

Operating Limit violations within its Reliability Coordinator Area.

R2.

Each Reliability Coordinator shall know the current status of all critical facilities whose failure, degradation or disconnection could result in an SOL or IROL violation.

Reliability Coordinators shall also know the status of any facilities that may be required to assist area restoration objectives.

C. Measures

M1.

The Reliability Coordinator shall have and provide upon request evidence that could include, but is not limited to, Energy Management System description documents, computer printouts, SCADA data collection, or other equivalent evidence that will be used to confirm that it monitors adjacent Reliability Coordinator Areas as necessary to ensure that, regardless of prior planned or unplanned events, the Reliability

Coordinator is able to determine any potential System Operating Limit and

Interconnection Reliability Operating Limit violations within its Reliability

Coordinator Area.

D. Compliance

1.


1.1.



1.2.






Adopted by the Régie de l'énergie (decision D-2015-059): May 4, 2015

Page 1 of 3






1.3.

Data Retention

Each Reliability Coordinator shall have current in-force documents used to show compliance with Measure 1.




1.4.


None.

2.

Levels of Non-Compliance for a Reliability Coordinator

2.1.


2.2.


2.3.


2.4.

Level 4: Did not produce acceptable evidence to confirm that it monitors adjacent

Reliability Coordinator Areas as necessary to ensure that, at any time, regardless of prior planned or unplanned events, the Reliability Coordinator is able to determine any potential System Operating Limit and Interconnection Reliability

Operating Limit violations within its Reliability Coordinator Area.


None identified.




Page 2 of 3


Version History

Version

0

Date Action


0 August 8, 2005 Removed “Proposed” from Effective

Date

1 February Adopted by Board of Trustees

2006

2006

Change Tracking

New

Errata

Revised

Revised




Page 3 of 3

Standard IRO-003-2 — Reliability Coordination - Wide-Area View




A. Introduction

1.

Title: Reliability Coordination - Wide-Area View

2.

Number: IRO-003-2

3.


4.


5.

Effective Date:

5.1.

Adoption of the standard by the Régie de l’énergie: May 4, 2015

5.2.


5.3.


B. Requirements

Specific provisions applicable to requirement R1:

•

Replace the term "Bulk Electric System" by the term "Main Transmission System" (RTP).

•

The Reliability Coordinator is not required to perform the monitoring specified in requirement R1 for generation facilities that are mainly used to supply industrial loads.

However, it shall perform that monitoring at the connection points of the system of the entities owning generation facilities for industrial use.

C. Measures


D. Compliance

1.


1.1.



1.2.



1.3.

Data Retention


1.4.



2.

Levels of Non-Compliance for a Reliability Coordinator


Adopted by Régie de l’énergie (Decision D-2015-059): May 4, 2015 Page QC-1 of 2

Standard IRO-003-2 — Reliability Coordination - Wide-Area View








Change Tracking

New


S ta n d a rd IRO-004-2 — Re lia b ility Co o rd in a tio n — Op e ra tio n s P la n n in g

A.

Introduction

1.

Title: Reliability Coordination — Operations Planning

2.

Number: IRO-004-2

3.

Purpose: Each Reliability Coordinator must conduct next-day reliability analyses for its

Reliability Coordinator Area to ensure the Bulk Electric System can be operated reliably in anticipated normal and Contingency conditions. System studies must be conducted to highlight potential interface and other operating limits, including overloaded transmission lines and transformers, voltage and stability limits, etc. Plans must be developed to alleviate System

Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) violations.

4.

Applicability

4.1.


4.2.


4.3.

Transmission Service Providers.

5.

Effective Date: In those jurisdictions where no regulatory approval is required, the standard shall become effective on the latter of either April 1, 2009 or the first day of the first calendar quarter, three months after BOT adoption.


B.

Requirements

R1.

Each Transmission Operator, Balancing Authority, and Transmission Service Provider shall comply with the directives of its Reliability Coordinator based on the next day assessments in the same manner in which it would comply during real time operating events.

C.

Measures

M1.

None

D.

Compliance

1.


Entities will be selected for an on-site audit at least every three years. For a selected 30-day period in the previous three calendar months prior to the on site audit, Reliability Coordinators will be asked to provide documentation showing that next-day reliability analyses were conducted each day to ensure the bulk power system could be operated in anticipated normal and Contingency conditions; and that they identified potential interface and other operating limits including overloaded transmission lines and transformers, voltage and stability limits, etc.

1.1.


1.2.


1.3.

Data Retention

1.4.


Adopted by NERC Board of Trustees: October 17, 2008

Adopted by the Régie (decision D-2015-059): May 4, 2015

Page 1 of 3


2. Violation Severity Levels

Requirement

R1

Lower

The responsible entity failed to comply with the directives of its Reliability Coordinator based on the next day assessments in the same manner in which it would comply during real time operating events on one (1) occasion during a calendar month.

Moderate

The responsible entity failed to comply with the directives of its Reliability Coordinator based on the next day assessments in the same manner in which it would comply during real time operating events on two (2) to three (3) occasions during a calendar month.

High

The responsible entity failed to comply with the directives of its Reliability Coordinator based on the next day assessments in the same manner in which it would comply during real time operating events on four (4) to five (5) occasions during a calendar month.

Severe

The responsible entity failed to comply with the directives of its Reliability Coordinator based on the next day assessments in the same manner in which it would comply during real time operating events on more than five (5) occasions during a calendar month.



Page 2 of 3


E.

Regional Variances

Version History

Version

0

0

1

2

2

Date

April 1, 2005

Action

Effective Date

August 8, 2005 Removed “Proposed” from Effective Date Errata

Replaced Levels of Non-compliance with the February 28, 2008 BOT approved


Retired R1 through R6, and associated

Measures, Data Retention, and VSLs

Revision

October 17,

2008


March 17, 2011 FERC Order issued approving IRO-004-2

(Clarification issued on July 13, 2011)

Change Tracking

New

Revision

Revision



Page 3 of 3

Standard IRO-004-2 — Reliability Coordination — Operations Planning




A. Introduction

1.

Title: Reliability Coordination – Operations Planning

2.

Number: IRO-004-2

3.


4.

Applicability:

Functions


Facilities


5.

Effective Date:

5.1.


5.2.


5.3.

Effective date of the standard and its appendix in Québec : January 1, 2016

B. Requirements


C. Measures


D. Compliance

1.


1.1.



1.2.



1.3.

Data Retention


1.4.



2.




Standard IRO-004-2 — Reliability Coordination — Operations Planning



E. Regional Variances





Change Tracking

New


Standard IRO-006-5 — Reliability Coordination — Trans mis s ion Loading Relief

A. Introduction

1.

Title: Reliability Coordination — Transmission Loading Relief (TLR)

2.

3.

Number: IRO-006-5

Purpose:

To ensure coordinated action between Interconnections when implementing Interconnection-wide transmission loading relief procedures to prevent or manage potential or actual SOL and IROL exceedances to maintain reliability of the bulk electric system.

4.

Applicability:

5.

4.1.

Reliability Coordinator.

4.2.

Balancing Authority.


First day of the first calendar quarter following the date 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 after the date this standard is approved by the NERC

Board of Trustees.

B. Requirements

R1.

Each Reliability Coordinator and Balancing Authority that receives a request pursuant to an Interconnection-wide transmission loading relief procedure (such as Eastern

Interconnection TLR, WECC Unscheduled Flow Mitigation, or congestion management procedures from the ERCOT Protocols) from any Reliability

Coordinator, Balancing Authority, or Transmission Operator in another

Interconnection to curtail an Interchange Transaction that crosses an Interconnection boundary shall comply with the request, unless it provides a reliability reason to the requestor why it cannot comply with the request. [

Violation Risk Factor: High

]

[

Time Horizon: Real-time Operations

]

C. Measures

M1.

Each Reliability Coordinator and Balancing Authority shall provide evidence (such as dated logs, voice recordings, Tag histories, and studies, in electronic or hard copy format) that, when a request to curtail an Interchange Transaction crossing an

Interconnection boundary pursuant to an Interconnection-wide transmission loading relief procedure was made from another Reliability Coordinator, Balancing

Authority, or Transmission Operator in that other Interconnection, it complied with the request or provided a reliability reason why it could not comply with the request

(R1).

D. Compliance

1.


1.1.


Regional Entity.

1.2.

Compliance Monitoring and Enforcement Processes:

Approved by the Board of Trustees on November 4, 2010


Page 1 of 4


The following processes may be used:

Compliance Audits

Self-Certifications

Spot Checking

Compliance Violation Investigations

Self-Reporting

Complaints

1.3.

Data Retention

The Reliability Coordinator and Balancing Authority shall each keep data or evidence to show compliance as identified below unless directed by its Compliance Enforcement

Authority to retain specific evidence for a longer period of time as part of an investigation:

-

The Reliability Coordinator and Balancing Authority shall maintain evidence to show compliance with R1 for the most recent twelve calendar months plus the current month.

-

If a Reliability Coordinator or Balancing Authority is found non-compliant, it shall keep information related to the non-compliance until found compliant or for the duration specified above, whichever is longer.

The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted subsequent audit records.

1.4.

Additional Compliance Information

None.



Page 2 of 4


R #

R1


Lower VSL Moderate VSL High VSL Severe VSL

The responsible entity received a request to curtail an Interchange Transaction crossing an Interconnection boundary pursuant to an

Interconnection-wide transmission loading relief procedure from a Reliability

Coordinator, Balancing

Authority, or Transmission

Operator, but the entity neither complied with the request, nor provided a reliability reason why it could not comply with the request.



Page 3 of 4


1

3

E. Variances

None.


None.

G. Version History

Version

0

Date Action


0

4

5

5

5


Date

August 8, 2005 Revised Attachment 1

February 26,

2007

Revised Purpose and Attachment 1 related to NERC NAESB split of the

TLR procedure

Completed NERC/NAESB split October 23,

2007

TBD Removed Attachment 1 and made into a new standard, eliminated unnecessary requirements.

November 4,

2010

Approved by the Board of Trustees

April 21, 2011 FERC Order issued approving IRO-006-

5 (approval effective June 27, 2011)

Change Tracking

New

Errata

Revision

Revision

Revision

Revision



Page 4 of 4

Standard IRO-006-5 — Reliability Coordination – Transmission Loading Relief (TLR)




A. Introduction

1.

Title: Reliability Coordination — Transmission Loading Relief (TLR)

2.

Number: IRO-006-5

3.


4.


5.

Effective Date:

5.1.


5.2.


5.3.


B. Requirements


C. Measures


D. Compliance

1.


1.1.


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 and Enforcement Processes


1.3.

Data Retention


1.4.



2.



E. Variances





Standard IRO-006-5 — Reliability Coordination – Transmission Loading Relief (TLR)






Change Tracking

New


Standard MOD-016-1.1 — Actual and Forecas t Demands , Net Energy for Load, Controllable DSM

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

: 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

:

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, MOD-

010, 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 (decision D-2013-176): October 30, 2013 Page 1 of 3


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.


1.1.


Compliance Monitor for Planning Authority: Regional Reliability Organization.

Compliance Monitor for Regional Reliability Organization: NERC.

1.2.


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.


T he 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.


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.


None identified.



Version History

Version Date

0

1

1

1.1

1.1

Action


November 1, 2006 Corrected sequential numbering problem in Sections R2. and R3.

May 2, 2006 Adopted by NERC Board of

Trustees

October 29, 2008 BOT adopted errata changes; updated version number to “1.1”

May 13, 2009 FERC Approved — Updated

Effective Date

Change Tracking

New

Errata

Errata

Revised


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


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.


4.

Applicability:


5.

Effective Date:

5.1.


5.2.

Adoption of the appendix by the Régie de l’énergie: October 30, 2013

5.3.


B. Requirements

Specific provision applicable to requirement R1.1:

•

Ignore the reference to the standards TPL-005, TPL-016, MOD-011, MOD-013, MOD-014,

MOD-015 and MOD-016.

C. Measures


D. Compliance

1.


1.1.



The NERC remains responsible for compliance monitoring of the Regional

Reliability Organization.

1.2.



1.3.

Data Retention


1.4.




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

2.








Change Tracking

New


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: MOD-020-0

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:

4.1.

Load-Serving Entity

4.2.

Transmission Planner

4.3.

Resource Planner

5.

Effective Date:

B. Requirements

April 1, 2005

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.


1.1.


Regional Reliability Organization.

1.2.


On request (within 30 calendar days).

1.3.

Data Retention

None specified.

1.4.


None.

2.


2.1.

Level 1: Interruptible Demands and DCLM data were provided to Reliability

Coordinators, Balancing Authorities, and Transmission Operators, but were incomplete.

2.2.




Adopted by the Régie de l'énergie (decision D-2013-176): October 30, 2013

1 of 2


2.3.


2.4.

Level 4: Interruptible Demands and DCLM data were not provided to Reliability

Coordinators, Balancing Authorities, and Transmission Operators.


1.

None identified.

Version History

Version Date

0 April 1, 2005

Action

Effective Date

Change Tracking

New



Adopted by the Régie de l'énergie (decision D-2013-176): October 30, 2013

2 of 2


Appendix QC-MOD-020-0

Provisions specific to the standard MOD-020-0 applicable in Québec


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.


4.


5.

Effective Date:

5.1.

Adoption date of the standard by the Régie de l'énergie: October 30, 2013

5.2.

Adoption date of the appendix by the Régie de l'énergie: October 30, 2013

5.3.


B. Requirements


C. Measures


D. Compliance

1.


1.1.



1.2.



1.3.

Data Retention


1.4.



2.







Appendix QC-MOD-020-0

Provisions specific to the standard MOD-020-0 applicable in Québec


Revision

0

Adopted Date Action

October 30, 2013 New Appendix

Change Tracking

New


S ta n d a rd P RC-001-1 — S ys te m P ro te c tio n Co o rd in a tio n

A.

Introduction

1.

Title:

2.

3.

Number:

Purpose:

System Protection Coordination

PRC-001-1

R2.

To ensure system protection is coordinated among operating entities.

4.

Applicability

4.1.

4.2.

4.3.


Generator Operators


B.

5.

Effective Date:

Requirements

R1.

January 1, 2007

Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar with the purpose and limitations of protection system schemes applied in its area.

Each Generator Operator and Transmission Operator shall notify reliability entities of relay or equipment failures as follows:

R2.1.

If a protective relay or equipment failure reduces system reliability, the

Generator Operator shall notify its Transmission Operator and Host Balancing

Authority. The Generator Operator shall take corrective action as soon as possible.

R2.2.

If a protective relay or equipment failure reduces system reliability, the

Transmission Operator shall notify its Reliability Coordinator and affected

Transmission Operators and Balancing Authorities. The Transmission

Operator shall take corrective action as soon as possible.

R3.

A Generator Operator or Transmission Operator shall coordinate new protective systems and changes as follows.

R3.1.

Each Generator Operator shall coordinate all new protective systems and all protective system changes with its Transmission Operator and Host Balancing

Authority.

R3.2.

Each Transmission Operator shall coordinate all new protective systems and all protective system changes with neighboring Transmission Operators and


R4.

Each Transmission Operator shall coordinate protection systems on major transmission lines and interconnections with neighboring Generator Operators, Transmission

Operators, and Balancing Authorities.

R5.

A Generator Operator or Transmission Operator shall coordinate changes in generation, transmission, load or operating conditions that could require changes in the protection systems of others:



Adopted by the Régie de l'énergie (decision D-2014-048): March 20, 2014

Page 1 of 4


R5.1.

Each Generator Operator shall notify its Transmission Operator in advance of changes in generation or operating conditions that could require changes in the

Transmission Operator’s protection systems.

R5.2.

Each Transmission Operator shall notify neighboring Transmission Operators in advance of changes in generation, transmission, load, or operating conditions that could require changes in the other Transmission Operators’ protection systems.

R6.

Each Transmission Operator and Balancing Authority shall monitor the status of each

Special Protection System in their area, and shall notify affected Transmission

Operators and Balancing Authorities of each change in status.

C.

Measures

M1.

Each Generator Operator and Transmission Operator shall have and provide upon request evidence that could include but is not limited to, revised fault analysis study, letters of agreement on settings, notifications of changes, or other equivalent evidence that will be used to confirm that there was coordination of new protective systems or changes as noted in Requirements 3, 3.1, and 3.2.

M2.

Each Transmission Operator and Balancing Authority shall have and provide upon request evidence that could include but is not limited to, documentation, electronic logs, computer printouts, or computer demonstration or other equivalent evidence that will be used to confirm that it monitors the Special Protection Systems in its area.

(Requirement 6 Part 1)

M3.

Each Transmission Operator and Balancing Authority shall have and provide upon request evidence that could include but is not limited to, operator logs, phone records, electronic-notifications or other equivalent evidence that will be used to confirm that it notified affected Transmission Operator and Balancing Authorities of changes in status of one of its Special Protection Systems. (Requirement 6 Part 2)

D.

Compliance

1.


1.1.



1.2.






Triggered Investigations (Notification of an investigation must be made within 60 days of an event or complaint of noncompliance. The entity will




Page 2 of 4


2.

3.

have up to 30 days to prepare for the investigation. An entity may request an extension of the preparation period and the extension will be considered by the Compliance Monitor on a case-by-case basis.)


1.3.

Data Retention

Each Generator Operator and Transmission Operator shall have current, in-force documents available as evidence of compliance for Measure 1.

Each Transmission Operator and Balancing Authority shall keep 90 days of historical data (evidence) for Measures 2 and 3.




1.4.


None.

Levels of Non-Compliance for Generator Operators:

2.1.

2.2.

2.3.

2.4.


Level 2 : Not applicable.


Level 4: Failed to provide evidence of coordination when installing new protective systems and all protective system changes with its Transmission

Operator and Host Balancing Authority as specified in R3.1.

Levels of Non-Compliance for Transmission Operators:

3.1.

3.2.

3.3.

3.4.


Level 2 : Not applicable.


Level 4: There shall be a separate Level 4 non-compliance, for every one of the following requirements that is in violation:

3.4.1

Failed to provide evidence of coordination when installing new protective systems and all protective system changes with neighboring Transmission

Operators and Balancing Authorities as specified in R3.2.




Page 3 of 4


3.4.2

Did not monitor the status of each Special Protection System, or did not notify affected Transmission Operators, Balancing Authorities of changes in special protection status as specified in R6.

4.

Levels of Non-Compliance for Balancing Authorities:

4.1.

4.2.

4.3.

4.4.

Level 1:

Level 2

Level 3:

Not applicable.

: Not applicable.

Not applicable.

Level 4: Did not monitor the status of each Special Protection System, or did not notify affected Transmission Operators, Balancing Authorities of changes in special protection status as specified in R6.

E.


None identified.

Version History

Version

0

Date Action


0

0


Date

August 25,

2005

Fixed Standard number in Introduction from PRC-001-1 to PRC-001-0

1 November 1,

2006


Change Tracking

New

Errata

Errata

Revised




Page 4 of 4

Standard PRC-001-1 — System Protection Coordination

Appendix QC-PRC-001-1

Provisions specific to the standard PRC-001-1 applicable in Québec


A. Introduction

1.

Title: System Protection Coordination

2.

Number: PRC-001-1

3.


4.


Functions


Facilities


5.

Effective Date:

5.1.

Adoption of the standard by the Régie de l’énergie: March 20, 2014

5.2.

Adoption of the appendix by the Régie de l’énergie: March 20, 2014

5.3.


B. Requirements

For the facilities adjacent to the RTP, the protective systems under requirements R3, R3.1, R3.2 and

R4 shall be coordinated for the failure protection (or reserve or backup protection) of the RTP that trips the element that is not part of the RTP to which it is connected if such protection exists.

Similarly, the failure protection (or reserve or backup protection) of an element that is not part of the RTP that trips an element of the RTP shall also be coordinated under requirements R3, R3.1,

R3.2 and R4 if a such protection does exist.

C. Measures


D. Compliance

1.


1.1.



1.2.



1.3.

Data Retention


1.4.


Adopted by Régie de l’énergie (Decision D-2014-048): March 20, 2014 Page QC-1 of 2

Standard PRC-001-1 — System Protection Coordination

Appendix QC-PRC-001-1

Provisions specific to the standard PRC-001-1 applicable in Québec


2.

Levels of Non-Compliance for Generator Operators :


3.

Levels of Non-Compliance for Transmission Operators:


4.

Levels of Non-Compliance for Balancing Authorities:






0 March 20, 2014 New appendix

Change Tracking

New

Adopted by Régie de l’énergie (Decision D-2014-048): March 20, 2014 Page QC-2 of 2

Standard TOP-001-1a — Reliability Responsibilities and Authorities

A.

Introduction

1.

2.

Title: Reliability Responsibilities and Authorities

Number:

TOP-001-1a

Purpose:

To ensure reliability entities have clear decision-making authority and capabilities to take appropriate actions or direct the actions of others to return the transmission system to normal conditions during an emergency.

3.

4.

Applicability

3.1.

3.2.

3.3.

3.4.



Generator Operators

Distribution Providers

3.5.

Load Serving Entities

Effective Date: authorities.

Immediately after approval of applicable regulatory

B.

Requirements

R1.

R2.

Each Transmission Operator shall have the responsibility and clear decision-making authority to take whatever actions are needed to ensure the reliability of its area and shall exercise specific authority to alleviate operating emergencies.

Each Transmission Operator shall take immediate actions to alleviate operating emergencies including curtailing transmission service or energy schedules, operating equipment (e.g., generators, phase shifters, breakers), shedding firm load, etc.

R3.

R4.

R5.

Each Transmission Operator, Balancing Authority, and Generator Operator shall comply with reliability directives issued by the Reliability Coordinator, and each

Balancing Authority and Generator Operator shall comply with reliability directives issued by the Transmission Operator, unless such actions would violate safety, equipment, regulatory or statutory requirements. Under these circumstances the

Transmission Operator, Balancing Authority or Generator Operator shall immediately inform the Reliability Coordinator or Transmission Operator of the inability to perform the directive so that the Reliability Coordinator or Transmission Operator can implement alternate remedial actions.

Each Distribution Provider and Load Serving Entity shall comply with all reliability directives issued by the Transmission Operator, including shedding firm load, unless such actions would violate safety, equipment, regulatory or statutory requirements.

Under these circumstances, the Distribution Provider or Load Serving Entity shall immediately inform the Transmission Operator of the inability to perform the directive so that the Transmission Operator can implement alternate remedial actions.

Each Transmission Operator shall inform its Reliability Coordinator and any other potentially affected Transmission Operators of real time or anticipated emergency conditions, and take actions to avoid, when possible, or mitigate the emergency.



R6.

R7.

R8.

Each Transmission Operator, Balancing Authority, and Generator Operator shall render all available emergency assistance to others as requested, provided that the requesting entity has implemented its comparable emergency procedures, unless such actions would violate safety, equipment, or regulatory or statutory requirements.

Each Transmission Operator and Generator Operator shall not remove Bulk Electric

System facilities from service if removing those facilities would burden neighboring systems unless:

R7.1.

R7.2.

For a generator outage, the Generator Operator shall notify and coordinate with the Transmission Operator. The Transmission Operator shall notify the

Reliability Coordinator and other affected Transmission Operators, and coordinate the impact of removing the Bulk Electric System facility.

For a transmission facility, the Transmission Operator shall notify and coordinate with its Reliability Coordinator. The Transmission Operator shall notify other affected Transmission Operators, and coordinate the impact of removing the Bulk Electric System facility.

R7.3.

When time does not permit such notifications and coordination, or when immediate action is required to prevent a hazard to the public, lengthy customer service interruption, or damage to facilities, the Generator Operator shall notify the Transmission Operator, and the Transmission Operator shall notify its Reliability Coordinator and adjacent Transmission Operators, at the earliest possible time.

During a system emergency, the Balancing Authority and Transmission Operator shall immediately take action to restore the Real and Reactive Power Balance. If the

Balancing Authority or Transmission Operator is unable to restore Real and Reactive

Power Balance it shall request emergency assistance from the Reliability Coordinator.

If corrective action or emergency assistance is not adequate to mitigate the Real and

Reactive Power Balance, then the Reliability Coordinator, Balancing Authority, and

Transmission Operator shall implement firm load shedding.

C.

Measures

M1.

Each Transmission Operator shall have and provide upon request evidence that could include, but is not limited to, signed agreements, an authority letter signed by an officer of the company, or other equivalent evidence that will be used to confirm that it has the authority, and has exercised the authority, to alleviate operating emergencies as described in Requirement 1.

M2.

M3.

If an operating emergency occurs the Transmission Operator that experienced the emergency shall have and provide upon request evidence that could include, but is not limited to, operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine if it took immediate actions to alleviate the operating emergency including curtailing transmission service or energy schedules, operating equipment (e.g., generators, phase shifters, breakers), shedding firm load, etc. (Requirement 2)

Each Transmission Operator, Balancing Authority, and Generator Operator shall have and provide upon request evidence such as operator logs, voice recordings or



M4.

M5.

M6.

M7.

transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine if it complied with its Reliability Coordinator’s reliability directives. If the Transmission Operator, Balancing Authority or Generator

Operator did not comply with the directive because it would violate safety, equipment, regulatory or statutory requirements, it shall provide evidence such as operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that it immediately informed the Reliability Coordinator of its inability to perform the directive. (Requirement 3)

Each Balancing Authority, Generator Operator, Distribution Provider and Load

Serving Entity shall have and provide upon request evidence such as operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine if it complied with its Transmission

Operator’s reliability directives. If the Balancing Authority, Generator Operator,

Distribution Provider and Load Serving Entity did not comply with the directive because it would violate safety, equipment, regulatory or statutory requirements, it shall provide evidence such as operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that it immediately informed the Transmission Operator of its inability to perform the directive. (Requirements 3 and 4)

The Transmission Operator shall have and provide upon request evidence that could include, but is not limited to, operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine if it informed its Reliability Coordinator and any other potentially affected

Transmission Operators of real time or anticipated emergency conditions, and took actions to avoid, when possible, or to mitigate an emergency. (Requirement 5)

The Transmission Operator, Balancing Authority, and Generator Operator shall each have and provide upon request evidence that could include, but is not limited to, operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine if it rendered assistance to others as requested, provided that the requesting entity had implemented its comparable emergency procedures, unless such actions would violate safety, equipment, or regulatory or statutory requirements. (Requirement 6)

The Transmission Operator and Generator Operator shall each have and provide upon request evidence that could include, but is not limited to, operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine if it notified either their

Transmission Operator in the case of the Generator Operator, or other Transmission

Operators, and the Reliability Coordinator when it removed Bulk Electric System facilities from service if removing those facilities would burden neighboring systems.

(Requirement 7)

D.

Compliance

1.


1.1.





1.2.



-


-


-


-



1.3.

Data Retention

Each Transmission Operator shall have the current in-force document to show that it has the responsibility and clear decision-making authority to take whatever actions are needed to ensure the reliability of its area. (Measure 1)

Each Transmission Operator shall keep 90 days of historical data (evidence) for

Measures 1 through 7, including evidence of directives issued for Measures 3 and

4.

Each Balancing Authority shall keep 90 days of historical data (evidence) for

Measures 3, 4 and 6 including evidence of directives issued for Measures 3 and 4.

Each Generator Operator shall keep 90 days of historical data (evidence) for

Measures 3, 4, 6 and 7 including evidence of directives issued for Measures 3 and

4.

Each Distribution Provider and Load-serving Entity shall keep 90 days of historical data (evidence) for Measure 4.



The Compliance Monitor shall keep the last periodic audit report and all supporting compliance data

1.4.




2.

3.

4.

None.

Levels of Non-Compliance for a Balancing Authority:

2.1.

2.2.

2.3.

2.4.

Level 1:

Not applicable.

Level 2:

Not applicable.

Level 3:

Not applicable.

Level 4:

There shall be a separate Level 4 non-compliance, for every one of the following requirements that is in violation:

2.4.1

Did not comply with a Reliability Coordinator’s or Transmission

Operator’s reliability directive or did not immediately inform the

Reliability Coordinator or Transmission Operator of its inability to perform that directive (R3)

2.4.2

Did not render emergency assistance to others as requested, in accordance with R6.

Levels of Non-Compliance for a Transmission Operator

3.1.

3.2.

3.3.

3.4.

Level 1:

Not applicable.

Level 2:

Not applicable.

Level 3:

Not applicable.

Level 4:


3.4.1

Does not have the documented authority to act as specified in R1.

3.4.2

Does not have evidence it acted with the authority specified in R1.

3.4.3

Did not take immediate actions to alleviate operating emergencies as specified in R2.

3.4.4

Did not comply with its Reliability Coordinator’s reliability directive or did not immediately inform the Reliability Coordinator of its inability to perform that directive, as specified in R3.

3.4.5

Did not inform its Reliability Coordinator and other potentially affected

Transmission Operators of real time or anticipated emergency conditions as specified in R5.

3.4.6

Did not take actions to avoid, when possible, or to mitigate an emergency as specified in R5.

3.4.7

Did not render emergency assistance to others as requested, as specified in

R6.

3.4.8

Removed Bulk Electric System facilities from service under conditions other than those specified in R7.1, 7.2, and 7.3, and removing those facilities burdened a neighbor system.

Levels of Non-Compliance for a Generator Operator:



4.1.

4.2.

4.3.

4.4.

Level 1:

Not applicable.

Level 2:

Not applicable.

Level 3:

Not applicable.

Level 4:


4.4.1

Did not comply with a Reliability Coordinator or Transmission Operator’s reliability directive or did not immediately inform the Reliability

Coordinator or Transmission Operator of its inability to perform that directive, as specified in R3.

4.4.2

Did not render all available emergency assistance to others as requested, unless such actions would violate safety, equipment, or regulatory or statutory requirements as specified in R6.

4.4.3

Removed Bulk Electric System facilities from service under conditions other than those specified in R7.1, 7.2, and 7.3, and burdened a neighbor system.

5.

Levels of Non-Compliance for a Distribution Provider or Load Serving Entity

5.1.

5.2.

5.3.

5.4.

Level 1:

Not applicable.

Level 2:

Not applicable.

Level 3:

Not applicable

Level 4:

Did not comply with a Transmission Operator’s reliability directive or immediately inform the Transmission Operator of its inability to perform that directive, as specified in R4.

E.


None identified.

Version History

Version Date

0

0

1

1a

1a

April 1, 2005

August 8, 2005

Action

November 1, 2006 Adopted by Board of Trustees

May 12, 2010

September 15,

2011

Effective Date

Removed “Proposed” from Effective

Date

Added Appendix 1 – Interpretation of

R8 approved by BOT on May 12, 2010

FERC Order issued approved the

Interpretation of R8 (FERC Order became effective November 21, 2011)

Change Tracking

New

Errata

Revised

Interpretation

Interpretation



Appendix 1

Requirement Number and Text of Requirement

R8

. During a system emergency, the Balancing Authority and Transmission Operator shall immediately take action to restore the Real and Reactive Power Balance. If the Balancing

Authority or Transmission Operator is unable to restore Real and Reactive Power Balance it shall request emergency assistance from the Reliability Coordinator. If corrective action or emergency assistance is not adequate to mitigate the Real and Reactive Power Balance, then the

Reliability Coordinator, Balancing Authority, and Transmission Operator shall implement firm load shedding.

Question

For Requirement R8 is the Balancing Authority responsibility to immediately take corrective action to restore Real Power Balance and is the TOP responsibility to immediately take corrective action to restore Reactive Power Balance?

Response

The answer to both questions is yes. According to the NERC

Glossary of Terms Used in

Reliability Standards

, the Transmission Operator is responsible for the reliability of its “local” transmission system, and operates or directs the operations of the transmission facilities.

Similarly, the Balancing Authority is responsible for maintaining load-interchange-generation balance, i.e., real power balance. In the context of this requirement, the Transmission Operator is the functional entity that balances reactive power. Reactive power balancing can be accomplished by issuing instructions to the Balancing Authority or Generator Operators to alter reactive power injection. Based on NERC Reliability Standard BAL-005-1b Requirement R6, the Transmission Operator has no requirement to compute an Area Control Error (ACE) signal or to balance real power. Based on NERC Reliability Standard VAR-001-1 Requirement R8, the

Balancing Authority is not required to resolve reactive power balance issues. According to TOP-

001-1 Requirement R3, the Balancing Authority is only required to comply with Transmission

Operator or Reliability Coordinator instructions to change injections of reactive power.



Appendix QC-TOP-001-1a

Provisions specific to the standard TOP-001-1a applicable in Québec


A. Introduction

1.

Title: Reliability Responsibilities and Authorities

2.

Number: TOP-001-1a

3.


4.

Applicability:

Functions


Facilities


5.

Effective Date:

5.1.


5.2.


5.3.


B. Requirements


C. Measures


D. Compliance

1.


1.1.



1.2.



1.3.

Data Retention


1.4.



2.

Levels of Non-Compliance for a Balancing Authority:


Adopted by the Régie de l’énergie (Decision D-2015-059): May 4, 2015 Page QC-1 of 2


Appendix QC-TOP-001-1a

Provisions specific to the standard TOP-001-1a applicable in Québec

3.

Levels of Non-Compliance for a Transmission Operator:


4.

Levels of Non-Compliance for a Generator Operator:


5.

Levels of Non-Compliance for a Distribution Provider or Load Serving Entity:




Appendix 1





Change Tracking

New

Adopted by the Régie de l’énergie (Decision D-2015-059): May 4, 2015 Page QC-2 of 2

Standard-TOP-003-1 — Planned Outage Coordination

A. Introduction

1.

Title: Planned Outage Coordination

2.

Number:

TOP-003-1

3.

Purpose:

Scheduled generator and transmission outages that may affect the reliability of interconnected operations must be planned and coordinated among Balancing Authorities,

Transmission Operators, and Reliability Coordinators.

4.

Applicability

4.1.

Generator Operators.

4.2.


4.3.


4.4.


5.


In those jurisdictions where no regulatory approval is required, the standard shall become effective on the latter of either April 1, 2009 or the first day of the first calendar quarter, three months after BOT adoption.


B. Requirements

R1.

Generator Operators and Transmission Operators shall provide planned outage information.

R1.1.

Each Generator Operator shall provide outage information daily to its Transmission

Operator for scheduled generator outages planned for the next day (any foreseen outage of a generator greater than 50 MW). The Transmission Operator shall establish the outage reporting requirements.

R1.2.

Each Transmission Operator shall provide outage information daily to affected

Balancing Authorities and Transmission Operators for scheduled generator and bulk transmission outages planned for the next day (any foreseen outage of a transmission line or transformer greater than 100 kV or generator greater than 50 MW) that may collectively cause or contribute to an SOL or IROL violation or a regional operating area limitation.

R1.3.

Such information shall be available by 1200 Central Standard Time for the Eastern

Interconnection and 1200 Pacific Standard Time for the Western Interconnection.

R2.

Each Transmission Operator, Balancing Authority, and Generator Operator shall plan and coordinate scheduled outages of system voltage regulating equipment, such as automatic voltage regulators on generators, supplementary excitation control, synchronous condensers, shunt and series capacitors, reactors, etc., among affected Balancing Authorities and

Transmission Operators as required.

R3.

Each Transmission Operator, Balancing Authority, and Generator Operator shall plan and coordinate scheduled outages of telemetering and control equipment and associated communication channels between the affected areas.

R4.

Each Reliability Coordinator shall resolve any scheduling of potential reliability conflicts.

Adopted by the Régie de l'énergie (Decision D-2015-059): May 4, 2015 Page 1 of 3


C. Measures

M1.

Evidence that the Generator Operator, Transmission Operator, and Balancing Authority reported and coordinated scheduled outage information as indicated in the requirements above.

D. Compliance

1.

Compliance Monitoring Process

Each Regional Reliability Organization shall conduct a review every three years to ensure that each responsible entity has a process in place to provide planned generator and/or bulk transmission outage information to their Reliability Coordinator, and with neighboring

Transmission Operators and Balancing Authorities.

Investigation: At the discretion of the Regional Reliability Organization or NERC, an investigation may be initiated to review the planned outage process of a monitored entity due to a complaint of non-compliance by another entity. Notification of an investigation must be made by the Regional Reliability Organization to the entity being investigated as soon as possible, but no later than 60 days after the event. The form and manner of the investigation will be set by NERC and/or the Regional Reliability Organization.

1.1.


A Reliability Coordinator makes a request for an outage to “not be taken” because of a reliability impact on the grid and the outage is still taken. The Reliability Coordinator must provide all its documentation within three business days to the Regional Reliability

Organization. Each Regional Reliability Organization shall report compliance and violations to NERC via the NERC Compliance Reporting process.

1.2.


One calendar year without a violation from the time of the violation.

1.3.

Data Retention

One calendar year.

1.4.


Not specified.

2.


(TBD)


None identified.

Version History

Version Date

0

0

1

April 1, 2005

August 8, 2005

Action

Effective Date

Removed “Proposed” from Effective Date

Modified R1.2

Modified M1

Change Tracking

New

Errata

Revised



1

1

Replaced Levels of Non-compliance with the

Feb 28, BOT approved Violation Severity Levels

(VSLs)

October 17, 2008 Adopted by NERC Board of Trustees

March 17, 2011 Order issued by FERC approving TOP-003-1

(approval effective 5/23/11)


Standard TOP-003-1 — Planned Outage Coordination

Appendix QC-TOP-003-1

Provisions specific to the standard TOP-003-1 applicable in Québec


A. Introduction

1.

Title: Planned Outage Coordination

2.

Number: TOP-003-1

3.


4.

Applicability:

Functions


Facilities


5.

Effective Date:

5.1.


5.2.


5.3.


B. Requirements

Specific provisions applicable to requirements R1.1 and R1.2:

•

The Generator Operator shall also provide the information required under requirements R1.1 and

R1.2 for any generator of a generation facility with a capability greater than 50 MVA.

•

Generators of wind farms are excluded.

Specific provisions regarding generation facilities for industrial use applicable to requirements

R1.1 and R2:

The Generator Operator whose facilities are mainly used to supply industrial loads is not required to provide the information required under requirements R1.1 and R2. However, it shall coordinate any generation variation that has an impact on the flow at the connection points of the system that facilities are mainly used to supply industrial loads with the Transmission Operator.

Specific provision applicable to requirement R1.3:

The information shall be available by 1200 Central Standard Time for the Quebec Interconnection.

C. Measures


Adopted by the Régie de l’énergie (Decision D-2015-059) : May 4, 2015 Page QC-1 de 5




D. Compliance

1.


1.1.



1.2.



1.3.

Data Retention


1.4.







2.



R1 The responsible entity failed to provide the information by 1200

Central Standard Time for the

Eastern Interconnection and the

Quebec Interconnection, and

1200 Pacific Standard Time for the Western Interconnection.

N/A

Moderate

N/A

High

R1.1

R1.2

R1.3

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

N/A

Severe

The Generator Operator failed to provide outage information, in accordance with its

Transmission Operators established outage reporting requirements, to its

Transmission Operator for scheduled generator outages planned for the next day (any foreseen outage of a generator greater than 5 MW).

OR

The Transmission Operator failed to provide outage information to affected

Balancing Authorities and

Transmission Operators for scheduled generator and bulk transmission outages planned for the next day (any foreseen outage of a transmission line or transformer greater than 100 kV or generator greater than 5 MW) that may collectively cause or contribute to an SOL or IROL violation or a regional operating area limitation.

N/A

N/A

N/A





Lower Moderate High Requirement

R2 N/A N/A N/A

R3

R4

N/A

N/A

N/A

N/A

N/A

N/A

Severe

The responsible entity failed to plan or coordinate scheduled outages of system voltage regulating equipment, such as automatic voltage regulators on generators, supplementary excitation control, synchronous condensers, shunt and series capacitors, reactors, etc., among affected Balancing Authorities and Transmission Operators when required.

The responsible entity failed to plan and coordinate scheduled outages of telemetering and control equipment and associated communication channels between the affected areas.

The Reliability Coordinator failed to resolve any scheduling of potential reliability conflicts.








Revision Adoption Date

0 May 4, 2015

Action

New appendix

Change Tracking

New


NORMES DE FIABILITÉ DE LA NERC JANVIER 2016

NORMES DE FIABILITÉ DE LA NERC

ADOPTÉES PAR LA RÉGIE DE L’ÉNERGIE,

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JANVIER 2016

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NORMES DE FIABILITÉ DE LA NERC JANVIER 2016

NORMES DE FIABILITÉ DE LA NERC

ADOPTÉES PAR LA RÉGIE DE L’ÉNERGIE,

À ÊTRE MISES EN VIGUEUR AU 1

JANVIER 2016

(VERSION ANGLAISE)

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